UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
| (Mark One) | |
| | |
| X | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | |
| | For the Fiscal Year Ended December 31, 20092012 |
| | OR |
| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
| | |
| | For the transition period from ____________ to ____________ |
Commission File Number | Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No. | | Commission File Number | Registrant, State of Incorporation or Organization, Address of Principal Executive Offices, Telephone Number, and IRS Employer Identification No. |
| 1-11299 | ENTERGY CORPORATION (a Delaware corporation) 639 Loyola Avenue New Orleans, Louisiana 70113 Telephone (504) 576-4000 72-1229752 | | 1-31508 | ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830 |
| | | | | |
| | | | | |
| 1-10764 | ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900 | | 0-05807 | ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3700 72-0273040 |
| | | | | |
| | | | | |
| 0-20371 | ENTERGY GULF STATES LOUISIANA, L.L.C. (a Louisiana limited liability company) 446 North Boulevard Baton Rouge, Louisiana 70802 Telephone (800) 368-3749 74-0662730 | | 1-34360 | ENTERGY TEXAS, INC. (a Texas corporation) 350 Pine Street Beaumont, Texas 77701 Telephone (409) 981-2000 61-1435798 |
| | | | | |
| | | | | |
| 1-32718 | ENTERGY LOUISIANA, LLC (a Texas limited liability company) 446 North Boulevard Baton Rouge, Louisiana 70802 Telephone (800) 368-3749 75-3206126 | | 1-09067 | SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One 1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777 |
Securities registered pursuant to Section 12(b) of the Act:
Registrant | Title of Class | Name of Each Exchange on Which Registered |
| | | |
| Entergy Corporation | Common Stock, $0.01 Par Value – 189,198,163178,092,521 shares outstanding at January 29, 201031, 2013 | New York Stock Exchange, Inc. Chicago Stock Exchange, Inc. |
| | | |
| Entergy Arkansas, Inc. | Mortgage Bonds, 6.7% Series due April 2032 Mortgage Bonds, 6.0%5.75% Series due November 2032
2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 4.90% Series due December 2052 | New York Stock Exchange, Inc. |
| | | |
| Entergy Louisiana, LLC | Mortgage Bonds, 7.6%6.0% Series due April 2032March 2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 5.875% Series due June 2041 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 5.25% Series due July 2052 | New York Stock Exchange, Inc. |
| | | |
| Entergy Mississippi, Inc. | Mortgage Bonds, 6.0% Series due November 2032 Mortgage Bonds, 7.25% Series due December 2032
| New York Stock Exchange, Inc. |
| Mortgage Bonds, 6.20% Series due April 2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 6.0% Series due May 2051 | New York Stock Exchange, Inc. |
| | |
| Entergy New Orleans, Inc. | Mortgage Bonds, 5.0% Series due December 2052 | New York Stock Exchange, Inc. |
| | | |
| Entergy Texas, Inc. | Mortgage Bonds, 7.875% Series due June 2039 | New York Stock Exchange, Inc. |
Securities registered pursuant to Section 12(g) of the Act:
| Registrant | Title of Class |
| | |
| Entergy Arkansas, Inc. | Preferred Stock, Cumulative, $100 Par Value Preferred Stock, Cumulative, $0.01 Par Value |
| | |
| Entergy Gulf States Louisiana, L.L.C. | Common Membership Interests |
| | |
| Entergy Mississippi, Inc. | Preferred Stock, Cumulative, $100 Par Value |
| | |
| Entergy New Orleans, Inc. | Preferred Stock, Cumulative, $100 Par Value |
| | |
| Entergy Texas, Inc. | Common Stock, no par value |
Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.
| | Yes | | No |
| | | | |
| Entergy Corporation | Ö | | |
| Entergy Arkansas, Inc. | | | Ö |
| Entergy Gulf States Louisiana, L.L.C. | | | Ö |
| Entergy Louisiana, LLC | Ö | | Ö |
| Entergy Mississippi, Inc. | | | Ö |
| Entergy New Orleans, Inc. | | | Ö |
| Entergy Texas, Inc. | | | Ö |
| System Energy Resources, Inc. | | | Ö |
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
| | Yes | | No |
| | | | |
| Entergy Corporation | | | Ö |
| Entergy Arkansas, Inc. | | | Ö |
| Entergy Gulf States Louisiana, L.L.C. | | | Ö |
| Entergy Louisiana, LLC | | | Ö |
| Entergy Mississippi, Inc. | | | Ö |
| Entergy New Orleans, Inc. | | | Ö |
| Entergy Texas, Inc. | | | Ö |
| System Energy Resources, Inc. | | | Ö |
Indicate by check mark whether the registrants (1) have filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days. Yes þ No o
Indicate by check mark whether Entergy Corporation hasthe registrants have submitted electronically and posted on Entergy'sEntergy’s corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes þ No o
Indicate by check mark whether Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy Resources have submitted electronically and posted on Entergy's corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrants were required to submit and post such files). Yes o No o
Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of the registrants'registrants’ knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. [Ö]
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of "accelerated“accelerated filer," "large” “large accelerated filer,"” and "smaller“smaller reporting company"company” in Rule 12b-2 of the Securities Exchange Act of 1934.
| | Large accelerated filer | | Accelerated filer | | Non-accelerated Non-accelerated filer
| | Smaller reporting company |
| | | | | | | | |
| Entergy Corporation | Ö | | | | | | |
| Entergy Arkansas, Inc. | | | | | Ö | | |
| Entergy Gulf States Louisiana, L.L.C. | | | | | Ö | | |
| Entergy Louisiana, LLC | | | | | Ö | | |
| Entergy Mississippi, Inc. | | | | | Ö | | |
| Entergy New Orleans, Inc. | | | | | Ö | | |
| Entergy Texas, Inc. | | | | | Ö | | |
| System Energy Resources, Inc. | | | | | Ö | | |
Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Act.) Yes o No þ
System Energy Resources meets the requirements set forth in General Instruction I(1) of Form 10-K and is therefore filing this Form 10-K with reduced disclosure as allowed in General Instruction I(2). System Energy Resources is reducing its disclosure by not including Part III, Items 10 through 13 in its Form 10-K.
The aggregate market value of Entergy Corporation Common Stock, $0.01 Par Value, held by non-affiliates as of the end of the second quarter of 2009,2012, was $15.2$12.0 billion based on the reported last sale price of $77.52$67.89 per share for such stock on the New York Stock Exchange on June 30, 2009.29, 2012. Entergy Corporation is the sole holder of the common stock of Entergy Arkansas, Inc., Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Entergy Corporation is the sole holder of the common stock of Entergy Louisiana Holdings, Inc., which is the sole holder of the common membership interests in Entergy Louisiana, LLC. Entergy Corporation is the sole holder of the common stock of EGS Holdings, Inc., which is the sole holder of the common membership interests in Entergy Gulf States Louisiana, L.L.C.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders, to be held May 7, 2010,3, 2013, are incorporated by reference into Part III hereof.
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| | SEC Form 10-K Reference Number | Page Number |
| | | |
Definitions | | i |
Entergy's Business | Part I. Item 1. | 1 |
| | 2iv |
| | 3vii |
Report of Management | | 4 |
| | |
| Part II. Item 7. | 51 |
Plan to Pursue Separation of Non-Utility Nuclear
| | 5 |
Results of Operations
| | 10 |
Liquidity and Capital Resources
| | 20 |
Rate, Cost-recovery, and Other Regulation
| | 35 |
Market and Credit Risk Sensitive Instruments
| | 44 |
Critical Accounting Estimates
| | 47 |
New Accounting Pronouncements
| | 54 |
| Part II. Item 6. | 5548 |
| | 5649 |
| Part II. Item 8. | 5750 |
| Part II. Item 8. | 51 |
| Part II. Item 8. | 5852 |
| Part II. Item 8. | 6054 |
Paid-in CapitalChanges in Equity for the Years Ended
| Part II. Item 8. | 6256 |
| Part II. Item 8. | 6357 |
| Part I. Item 1. | 205 |
Customers
| | 194 |
Electric Energy Sales
| | 194 |
Retail Rate Regulation
| | 196 |
Property and Other Generation Resources
| | 200 |
Fuel Supply
| | 203 |
| | 206 |
Service Companies
| | 209 |
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
| | 210 |
Entergy Louisiana Corporate Restructuring
| | 211 |
Earnings Ratios of Registrant Subsidiaries
| | 212 |
Non-Utility Nuclear
| Part I. Item 1. | 212205 |
Property
| | 212 |
Energy and Capacity Sales
| | 214 |
Fuel Supply
| | 216 |
Other Business Activities
| | 216 |
| Part I. Item 1. | 216224 |
Property
| | 217 |
| Part I. Item 1. | 217229 |
Regulation of Entergy's Business
| Part I. Item 1. | 218 |
| | 218244 |
| | 218246 |
| | 219246 |
Regulation of the Nuclear Power Industry
| | 220 |
Environmental Regulation
| | 222 |
Litigation
| | 235 |
Employees
| | 239 |
| Part I. Item 1A. | 240247 |
Unresolved Staff Comments | Part I. Item 1B. | None |
| Entergy Arkansas, Inc. and Subsidiaries | | |
| Part II. Item 7. | 258 |
Results of Operations
| | 258 |
Liquidity and Capital Resources
| | 261 |
State and Local Rate Regulation
| | 266 |
Co-Owner-Initiated Proceedings at the FERC
| | 268 |
Federal Regulation
| | 269 |
Utility Restructuring
| | 269 |
Nuclear Matters
| | 269 |
Environmental Risks
| | 269 |
Critical Accounting Estimates
| | 270 |
New Accounting Pronouncements
| | 271 |
| | 272283 |
| Part II. Item 8. | 273284 |
| Part II. Item 8. | 275285 |
| Part II. Item 8. | 276286 |
2008,2012, 2011, and 20072010
| Part II. Item 8. | 278288 |
| Part II. Item 6. | 279289 |
| Entergy Gulf States Louisiana, L.L.C. | | |
| Part II. Item 7. | 280 |
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy
Gulf States Louisiana and Entergy Texas
| | 280 |
Results of Operations
| | 281 |
Liquidity and Capital Resources
| | 285 |
State and Local Rate Regulation
| | 290 |
Federal Regulation
| | 292 |
Industrial and Commercial Customers
| | 292 |
Nuclear Matters
| | 293 |
Environmental Risks
| | 293 |
Critical Accounting Estimates
| | 293 |
New Accounting Pronouncements
| | 294 |
| | 295308 |
| Part II. Item 8. | 296309 |
| Part II. Item 8. | 310 |
| Part II. Item 8. | 297311 |
| Part II. Item 8. | 298312 |
Ended December 31, 2009, 2008,2012, | Part II. Item 8. | 300314 |
| Part II. Item 6. | 301315 |
| Entergy Louisiana, LLC and Subsidiaries | | |
| Part II. Item 7. | 302 |
Results of Operations
| | 302 |
Liquidity and Capital Resources
| | 305 |
State and Local Rate Regulation
| | 312 |
Federal Regulation
| | 314 |
Industrial and Commercial Customers
| | 314 |
Nuclear Matters
| | 314 |
Environmental Risks
| | 315 |
Critical Accounting Estimates
| | 315 |
New Accounting Pronouncements
| | 316 |
| | 317334 |
| Part II. Item 8. | 318335 |
| Part II. Item 8. | 336 |
| Part II. Item 8. | 319337 |
| Part II. Item 8. | 320338 |
| Part II. Item 8. | 322340 |
| Part II. Item 6. | 323341 |
| Entergy Mississippi, Inc. | | |
| Part II. Item 7. | 324342 |
Results of Operations
| | 324 |
Liquidity and Capital Resources
| | 327 |
State and Local Rate Regulation
| | 331 |
Federal Regulation
| | 332 |
Critical Accounting Estimates
| | 332 |
New Accounting Pronouncements
| | 334 |
| | 335353 |
| Part II. Item 8. | 336354 |
| Part II. Item 8. | 337355 |
| Part II. Item 8. | 338356 |
2008,2012, 2011, and 20072010
| Part II. Item 8. | 340358 |
| Part II. Item 6. | 341359 |
| Entergy New Orleans, Inc. | | |
| Part II. Item 7. | 342360 |
Results of Operations
| | 342 |
Hurricane Katrina
| | 344 |
Liquidity and Capital Resources
| | 346 |
State and Local Rate Regulation
| | 349 |
Federal Regulation
| | 350 |
Environmental Risks
| | 351 |
Critical Accounting Estimates
| | 351 |
New Accounting Pronouncements
| | 352 |
| | 353371 |
| Part II. Item 8. | 354372 |
| Part II. Item 8. | 355373 |
| Part II. Item 8. | 356374 |
2008,2012, 2011, and 2007
| Part II. Item 8. | 358 |
Selected Financial Data - Five-Year Comparison
| Part II. Item 6. | 359 |
Entergy Texas, Inc. | | |
Management's Financial Discussion and Analysis
| Part II. Item 7. | 360 |
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy
Gulf States Louisiana and Entergy Texas
| | 360 |
Results of Operations
| | 361 |
Liquidity and Capital Resources
| | 364 |
Electric Industry Restructing
| | 369 |
State and Local Rate Regulation
| | 370 |
Federal Regulation
| | 372 |
Industrial and Commercial Customers
| | 372 |
Environmental Risks
| | 372 |
Critical Accounting Estimates
| | 373 |
New Accounting Pronouncements
| | 374 |
Report of Independent Registered Public Accounting Firm
| | 375 |
Consolidated Income Statements For the Years Ended December 31, 2009,
2008, and 20072010
| Part II. Item 8. | 376 |
| Part II. Item 6. | 377 |
| Entergy Texas, Inc. and Subsidiaries | | |
| Part II. Item 7. | 378 |
| | 389 |
| Part II. Item 8. | 390 |
| Part II. Item 8. | 377391 |
| Part II. Item 8. | 378392 |
Paid-in CapitalChanges in Common Equity for the Years
| Part II. Item 8. | 380394 |
| Part II. Item 6. | 381395 |
| System Energy Resources, Inc. | | |
| Part II. Item 7. | 382396 |
Results of Operations
| | 382 |
Liquidity and Capital Resources
| | 382 |
Nuclear Matters
| | 385 |
Environmental Risks
| | 385 |
Critical Accounting Estimates
| | 386 |
New Accounting Pronouncements
| | 387 |
| | 388403 |
| Part II. Item 8. | 389404 |
| Part II. Item 8. | 391405 |
| Part II. Item 8. | 392406 |
2008,2012, 2011, and 20072010
| Part II. Item 8. | 394408 |
| Part II. Item 6. | 395409 |
| Part I. Item 2. | 396410 |
| Part I. Item 3. | 396410 |
Submission of Matters to a Vote of Security Holders | Part I. Item 4. | 396410 |
| Part II. and Part III. Item 10. | 396410 |
| Part II. Item 5. | 398412 |
| Part II. Item 6. | 399414 |
| Part II. Item 7. | 399414 |
| Part II. Item 7A. | 400414 |
| Part II. Item 8. | 400414 |
| Part II. Item 9. | 400414 |
| Part II. Item 9A. | 400414 |
| Part II. Item 9A. | 402416 |
| Part III. Item 10. | 410424 |
| Part III. Item 11. | 415429 |
| Part III. Item 12. | 470494 |
| Part III. Item 13. | 474497 |
| Part III. Item 14. | 475499 |
| Part IV. Item 15. | 478502 |
| | 479503 |
| | 487511 |
| | 489513 |
| | S-1 |
| | E-1 |
This combined Form 10-K is separately filed by Entergy Corporation and its seven "Registrant Subsidiaries"“Registrant Subsidiaries”: Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. Information contained herein relating to any individual company is filed by such company on its own behalf. Each company makes representations only as to itself and makes no other representations whatsoever as to any other company.
The report should be read in its entirety as it pertains to each respective reporting company. No one section of the report deals with all aspects of the subject matter. Separate Item 6, 7, and 8 sections are provided for each reporting company, except for the Notes to the financial statements. The Notes to the financial statements for all of the reporting companies are combined. All Items other than 6, 7, and 8 are combined for the reporting companies.
In this combined report and from time to time, Entergy Corporation and the Registrant Subsidiaries each makes statements as a registrant concerning its expectations, beliefs, plans, objectives, goals, strategies, and future events or performance. Such statements are "forward-looking statements"“forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. Words such as "may," "will," "could," "project," "believe," "anticipate," "intend," "expect," "estimate," "continue," "potential," "plan," "predict," "forecast,"“may,” “will,” “could,” “project,” “believe,” “anticipate,” “intend,” “expect,” “estimate,” “continue,” “potential,” “plan,” “predict,” “forecast,” and other similar words or expressions are intended to identify forward-looking statements but are not the only means to identify these statements. Although each of these registrants believes that these forward-looking statements and the underlying assumptions are reasonable, it cannot provide assurance that they will prove correct. Any forward-looking statement is based on information current as of the date of this combined report and speaks only as of the date on which such statement is made. Except to the extent required by the federal securities laws, these registrants undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events, or otherwise.
Forward-looking statements involve a number of risks and uncertainties. There are factors that could cause actual results to differ materially from those expressed or implied in the forward-looking statements, including those factors discussed or incorporated by reference in (a) Item 1A. Risk Factors, (b) Management's Financial Discussion and Analysis, and (c) the following factors (in addition to others described elsewhere in this combined report and in subsequent securities filings):
| · | resolution of pending and future rate cases and negotiations, including various performance-based rate discussions, and implementation of legislation ending the Texas transition to competition, and other regulatory proceedings, including those related to Entergy's System Agreement, Entergy'sEntergy’s utility supply plan, recovery of storm costs, and recovery of fuel and purchased power costscosts; |
| · | the termination of Entergy Arkansas’s and Entergy Mississippi’s participation in the System Agreement in December 2013 and November 2015, respectively; |
| · | regulatory and operating challenges and uncertainties associated with the Utility operating companies’ proposal to move to the MISO RTO; |
| · | changes in utility regulation, including the beginning or end of retail and wholesale competition, the ability to recover net utility assets and other potential stranded costs, the operations of the independent coordinator of transmission for Entergy's utility service territory, and the application of more stringent transmission reliability requirements or market power criteria by the FERCFERC; |
| · | changes in regulation of nuclear generating facilities and nuclear materials and fuel, including possible shutdown of nuclear generating facilities, particularly those owned or operated by the Non-Utility NuclearEntergy Wholesale Commodities business, and the effects of new or existing safety or environmental concerns regarding nuclear power plants and nuclear fuel; |
| · | resolution of pending or future applications, and related regulatory proceedings and litigation, for license renewals or modifications of nuclear generating facilitiesfacilities; |
| · | the performance of and deliverability of power from Entergy's generating plants,Entergy’s generation resources, including the capacity factors at its nuclear generating facilitiesfacilities; |
| · | Entergy's ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commoditiescommodities; |
| · | prices for power generated by Entergy'sEntergy’s merchant generating facilities and the ability to hedge, meet credit support requirements for hedges, sell power forward or otherwise reduce the market price risk associated with those facilities, including the Non-Utility Nuclear plants, and Entergy Wholesale Commodities nuclear plants; |
| · | the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy'sEntergy’s ability to meet credit support requirements for fuel and power supply contractscontracts; |
| · | volatility and changes in markets for electricity, natural gas, uranium, and other energy-related commoditiescommodities; |
| · | changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; |
FORWARD-LOOKING INFORMATION (Concluded)
| · | changes in environmental, tax, and other laws, including requirements for reduced emissions of sulfur, nitrogen, carbon, greenhouse gases, mercury, and other substances,regulated air emissions, and changes in costs of compliance with environmental and other laws and regulationsregulations; |
| · | uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposaldisposal; |
| · | risks associated with the proposed spin-off and subsequent merger of Entergy’s electric transmission business into a subsidiary of ITC Holdings Corp., including the risk that Entergy and the Utility operating companies may not be able to timely satisfy the conditions or obtain the approvals required to complete such transaction or such approvals may contain material restrictions or conditions, and the risk that if completed, the transaction may not achieve its anticipated results; |
| · | variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, and ice storms, (including most recently, Hurricane Gustavor other weather events and Hurricane Ike and the January 2009 ice storm in Arkansas) and recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insuranceinsurance; |
FORWARD-LOOKING INFORMATION (Concluded)
| · | effects of climate change, and environmental and other regulatory obligations intended to compel reductions in carbon dioxide emissionschange; |
| · | Entergy'schanges in the quality and availability of water supplies; |
| · | Entergy’s ability to manage its capital projects and operation and maintenance costscosts; |
| · | Entergy'sEntergy’s ability to purchase and sell assets at attractive prices and on other attractive termsterms; |
| · | the economic climate, and particularly economic conditions in Entergy'sEntergy’s Utility service territoryarea and the Northeast United States and events that could influence economic conditions in those areas; |
| · | the effects of Entergy'sEntergy’s strategies to reduce tax paymentspayments; |
| · | changes in the financial markets, particularly those affecting the availability of capital and Entergy'sEntergy’s ability to refinance existing debt, execute share repurchase programs, and fund investments and acquisitionsacquisitions; |
| · | actions of rating agencies, including changes in the ratings of debt and preferred stock, changes in general corporate ratings, and changes in the rating agencies'agencies’ ratings criteriacriteria; |
| · | changes in inflation and interest ratesrates; |
| · | the effect of litigation and government investigations or proceedingsproceedings; |
| · | advances in technologytechnology; |
| · | the potential effects of threatened or actual terrorism, cyber attacks or data security breaches, including increased security costs, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion; |
| · | Entergy'sEntergy’s ability to attract and retain talented management and directorsdirectors; |
| · | changes in accounting standards and corporate governancegovernance; |
| · | declines in the market prices of marketable securities and resulting funding requirements for Entergy'sEntergy’s defined benefit pension and other postretirement benefit plansplans; |
| · | future wage and employee benefit costs, including changes in discount rates and returns on benefit plan assets; |
| · | changes in decommissioning trust fund values or earnings or in the timing of or cost to decommission nuclear plant sitessites; |
| · | the effectiveness of Entergy’s risk management policies and procedures and the ability and willingness of its counterparties to satisfy their financial and performance commitments; |
| · | factors that could lead to impairment of long-lived assets; and |
| · | the ability to successfully complete merger, acquisition, or divestiture plans, regulatory or other limitations imposed as a result of merger, acquisition, or divestiture, and the success of the business following a merger, acquisition, or divestituredivestiture. |
· | and the risks inherent in the contemplated Non-Utility Nuclear spin-off, joint venture, and related transactions. Entergy Corporation cannot provide any assurances that the spin-off or any of the proposed transactions related thereto will be completed, nor can it give assurances as to the terms on which such transactions will be consummated. The transaction is subject to certain conditions precedent, including regulatory approvals and the final approval by the Board. |
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Certain abbreviations or acronyms used in the text and notes are defined below:
| Abbreviation or Acronym | Term | |
| | |
AEEC | Arkansas Electric Energy Consumers |
| AFUDC | Allowance for Funds Used During Construction | |
| ALJ | Administrative Law Judge | |
| ANO 1 and 2 | Units 1 and 2 of Arkansas Nuclear One Steam Electric Generating Station (nuclear), owned by Entergy Arkansas | |
| APSC | Arkansas Public Service Commission | |
| ASLB | Atomic Safety and Licensing Board, the board within the NRC that conducts hearings and performs other regulatory functions that the NRC authorizes | |
| ASU | Accounting Standards Update issued by the FASB | |
| Board | Board of Directors of Entergy Corporation | |
| Cajun | Cajun Electric Power Cooperative, Inc. | |
| capacity factor | Actual plant output divided by maximum potential plant output for the period |
CDBG | Community Development Block Grant |
| City Council or Council | Council of the City of New Orleans, Louisiana |
CPI-U | Consumer Price Index - Urban |
| DOE | United States Department of Energy | |
EITFD. C. Circuit | FASB's Emerging Issues Task ForceU.S. Court of Appeals for the District of Columbia Circuit | |
| Entergy | Entergy Corporation and its direct and indirect subsidiaries | |
| Entergy Corporation | Entergy Corporation, a Delaware corporation | |
| Entergy Gulf States, Inc. | Predecessor company for financial reporting purposes to Entergy Gulf States Louisiana that included the assets and business operations of both Entergy Gulf States Louisiana and Entergy Texas | |
| Entergy Gulf States Louisiana | Entergy Gulf States Louisiana, L.L.C., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. and the successor company to Entergy Gulf States, Inc. for financial reporting purposes. The term is also used to refer to the Louisiana jurisdictional business of Entergy Gulf States, Inc., as the context requires. | |
| Entergy-Koch | A joint venture equally owned by subsidiaries of Entergy and Koch Industries, Inc. Entergy-Koch'sEntergy-Koch’s pipeline and trading businesses were sold in 2004. | |
| Entergy Texas | Entergy Texas, Inc., a company formally created as part of the jurisdictional separation of Entergy Gulf States, Inc. The term is also used to refer to the Texas jurisdictional business of Entergy Gulf States, Inc., as the context requires. | |
Entergy Wholesale Commodities (EWC) | Entergy’s non-utility business segment primarily comprised of the ownership and operation of six nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by those plants to wholesale customers | |
| EPA | United States Environmental Protection Agency |
EPDC | Entergy Power Development Corporation, a wholly-owned subsidiary of Entergy Corporation |
| ERCOT | Electric Reliability Council of Texas | |
| FASB | Financial Accounting Standards Board |
FEMA | Federal Emergency Management Agency |
| FERC | Federal Energy Regulatory Commission | |
| firm LD | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, the defaulting party must compensate the other party as specified in the contract | |
FSPFitzPatrick | FASB Staff PositionJames A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Grand Gulf | Unit No. 1 of Grand Gulf Steam Electric GeneratingNuclear Station (nuclear), 90% owned or leased by System Energy | |
| GWh | Gigawatt-hour(s), which equals one million kilowatt-hours | |
DEFINITIONS (Continued)
| Abbreviation or Acronym | Term |
| |
| Independence | Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power |
DEFINITIONS (Continued)
Abbreviation or AcronymIndian Point 2 | TermUnit 2 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Indian Point 3 | Unit 3 of Indian Point Energy Center (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| IRS | Internal Revenue Service |
| ISO | Independent System Operator |
| kV | Kilovolt |
| kW | Kilowatt, which equals one thousand watts |
| kWh | Kilowatt-hour(s) |
| LDEQ | Louisiana Department of Environmental Quality |
| LPSC | Louisiana Public Service Commission |
| Mcf | 1,000 cubic feet of gas |
| MISO | Midwest Independent Transmission System Operator, Inc., a regional transmission organization |
| MMBtu | One million British Thermal Units |
| MPSC | Mississippi Public Service Commission |
| MW | Megawatt(s), which equals one thousand kilowatt(s) |
| MWh | Megawatt-hour(s) |
| Nelson Unit 6 | Unit No. 6 (coal) of the Nelson Steam Electric Generating Station, 70% of which is co-owned by Entergy Gulf States Louisiana (57.5%) and Entergy Texas (42.5%), and 10.9% of which is owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Net debt to net capital ratio | Gross debt less cash and cash equivalents divided by total capitalization less cash and cash equivalents |
| Net MW in operation | Installed capacity owned and operated |
Non-Utility Nuclear | Entergy's business segment that owns and operates six nuclear power plants and sells electric power produced by those plants to wholesale customers |
| NRC | Nuclear Regulatory Commission |
| NYPA | New York Power Authority |
| OASIS | Open Access Same Time Information Systems |
| Palisades | Palisades Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Pilgrim | Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| PPA | Purchased power agreement |
production cost | Cost in $/MMBtu associated with delivering gas, excluding the cost of the gas or power purchase agreement |
| PRP | Potentially responsible party (a person or entity that may be responsible for remediation of environmental contamination) |
| PUCT | Public Utility Commission of Texas |
PUHCA 1935 | Public Utility Holding Company Act of 1935, as amended |
PUHCA 2005 | Public Utility Holding Company Act of 2005, which repealed PUHCA 1935, among other things |
PURPA | Public Utility Regulatory Policies Act of 1978 |
| Registrant Subsidiaries | Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. |
DEFINITIONS (Concluded)
| Abbreviation or Acronym | Term |
| |
| Ritchie Unit 2 | Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil) |
| River Bend | River Bend Steam Electric Generating Station (nuclear), owned by Entergy Gulf States Louisiana |
| RTO | Regional transmission organization |
| SEC | Securities and Exchange Commission |
SFAS | Statement of Financial Accounting Standards as promulgated by the FASB |
| SMEPA | South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf |
spark spread | Dollar difference between electricity prices per unit and natural gas prices after assuming a conversion ratio for the number of natural gas units necessary to generate one unit of electricity |
| System Agreement | Agreement, effective January 1, 1983, as modified, among the Utility operating companies relating to the sharing of generating capacity and other power resources |
| System Energy | System Energy Resources, Inc. |
| System Fuels | System Fuels, Inc. |
DEFINITIONS (Concluded)
Abbreviation or Acronym | Term |
| |
| TWh | Terawatt-hour(s), which equals one billion kilowatt-hours |
unit-contingentU.K. | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to the buyer for any damagesUnited Kingdom of Great Britain and Northern Ireland |
| Unit Power Sales Agreement | Agreement, dated as of June 10, 1982, as amended and approved by FERC, among Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy, relating to the sale of capacity and energy from System Energy'sEnergy’s share of Grand Gulf |
UK | The United Kingdom of Great Britain and Northern Ireland |
| Utility | Entergy'sEntergy’s business segment that generates, transmits, distributes, and sells electric power, with a small amount of natural gas distribution |
| Utility operating companies | Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Vermont Yankee | Vermont Yankee Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Waterford 3 | Unit No. 3 (nuclear)(nuclear) of the Waterford Steam Electric Generating Station, 100% owned or leased by Entergy Louisiana |
| weather-adjusted usage | Electric usage excluding the effects of deviations from normal weather |
| White Bluff | White Bluff Steam Electric Generating Station, 57% owned by Entergy Arkansas |
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Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of aggregate electric generating capacity, and Entergy is the second-largest nuclear power generator in the United States. Entergy delivers electricity to 2.7 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of $10.7 billion in 2009 and had approximately 15,000 employees as of December 31, 2009.MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy operates primarily through two business segments: Utility and Non-Utility Nuclear.Entergy Wholesale Commodities.
| · | The Utilitygenerates, transmits, distributes, business segment includes the generation, transmission, distribution, and sellssale of electric power in a four-state service territory that includes portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business. As discussed in more detail in “Plan to Spin Off the Utility’s Transmission Business,” in December 2011, Entergy entered into an agreement to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp. |
| · | The Non-Utility NuclearEntergy Wholesale Commodities ownsbusiness segment includes the ownership and operatesoperation of six nuclear power plants located in the northern United States and sellsthe sale of the electric power produced by those plants primarily to wholesale customers. This business also provides services to other nuclear power plant owners. As discussed furtherEntergy Wholesale Commodities also owns interests in "Management's Financial Discussion and Analysis," in November 2007,non-nuclear power plants that sell the Board approved a planelectric power produced by those plants to pursue a separation of the Non-Utility Nuclear business from Entergy through a tax-free spin-off of Non-Utility Nuclear to Entergy shareholders.wholesale customers. |
In addition toFollowing are the percentages of Entergy’s consolidated revenues and net income generated by its two primary, reportable, operating segments and the percentage of total assets held by them.
| | | % of Revenue | | % of Net Income | | % of Total Assets |
| Segment | | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 | | 2012 | | 2011 | | 2010 |
| | | | | | | | | | | | | | | | | | | |
| Utility | | 78 | | 79 | | 78 | | 110 | | 82 | | 65 | | 82 | | 80 | | 80 |
| Entergy Wholesale Commodities | | 22 | | 21 | | 22 | | 5 | | 36 | | 36 | | 22 | | 24 | | 26 |
| Parent & Other | | - | | - | | - | | (15) | | (18) | | (1) | | (4) | | (4) | | (6) |
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy also operatesArkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the non-nuclear wholesaleestimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets business. The non-nuclear wholesaleof approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets business sellsin accordance with its accounting policies and based on the historic treatment of such costs in its service areas because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to wholesale customerspredict with certainty the electric power produced by power plantsdegree of success it may have in its recovery initiatives, the amount of restoration costs that it owns while it focuses on improving performance and exploring salesmay ultimately recover, or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view.the timing of such recovery.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| OPERATING INFORMATION | |
| For the Years Ended December 31, 2009, 2008, and 2007 | |
| | | | | | | | | | |
| | | Utility (a) | | | Non-Utility
Nuclear | | Entergy Consolidated (a) | |
| | | (In Thousands) | |
| 2009 | | | | | | | | | |
| Operating revenues | | $ | 8,055,353 | | | $ | 2,555,254 | | | $ | 10,745,650 | |
| Operating expenses | | $ | 6,731,528 | | | $ | 1,553,686 | | | $ | 8,461,124 | |
| Other income | | $ | 235,968 | | | $ | 64,603 | | | $ | 169,708 | |
| Interest and other charges | | $ | 462,206 | | | $ | 55,884 | | | $ | 570,444 | |
| Income taxes | | $ | 388,682 | | | $ | 379,266 | | | $ | 632,740 | |
| Net income | | $ | 708,905 | | | $ | 631,020 | | | $ | 1,251,050 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | |
| Operating revenues | | $ | 10,318,630 | | | $ | 2,558,378 | | | $ | 13,093,756 | |
| Operating expenses | | $ | 9,078,502 | | | $ | 1,434,425 | | | $ | 10,810,589 | |
| Other income | | $ | 161,512 | | | $ | 46,360 | | | $ | 169,287 | |
| Interest and other charges | | $ | 425,216 | | | $ | 53,926 | | | $ | 608,921 | |
| Income taxes | | $ | 371,281 | | | $ | 319,107 | | | $ | 602,998 | |
| Net income | | $ | 605,144 | | | $ | 797,280 | | | $ | 1,240,535 | |
| | | | | | | | | | | | | |
| 2007 | | | | | | | | | | | | |
| Operating revenues | | $ | 9,255,075 | | | $ | 2,029,666 | | | $ | 11,484,398 | |
| Operating expenses | | $ | 7,910,659 | | | $ | 1,312,577 | | | $ | 9,428,030 | |
| Other income | | $ | 164,383 | | | $ | 87,256 | | | $ | 255,055 | |
| Interest and other charges | | $ | 422,382 | | | $ | 34,738 | | | $ | 637,052 | |
| Income taxes | | $ | 382,025 | | | $ | 230,407 | | | $ | 514,417 | |
| Net income | | $ | 704,393 | | | $ | 539,200 | | | $ | 1,159,954 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| CASH FLOW INFORMATION |
| For the Years Ended December 31, 2009, 2008, and 2007 |
| | | | | | | | | | | | | |
| | | Utility (a) | | | Non-Utility Nuclear | | Entergy Consolidated (a) | |
| | | (In Thousands) |
| 2009 | | | | | | | | | | | | |
| Net cash flow provided by operating activities | | $ | 1,586,020 | | | $ | 2,434,449 | | | $ | 2,933,158 | |
| Net cash flow used in investing activities | | $ | (1,465,824 | ) | | $ | (1,978,037 | ) | | $ | (2,094,394 | ) |
| Net cash flow provided by (used in) financing activities | | $ | 553,107 | | | $ | (474,028 | ) | | $ | (1,048,388 | ) |
| | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | |
| Net cash flow provided by operating activities | | $ | 2,379,258 | | | $ | 1,255,284 | | | $ | 3,324,328 | |
| Net cash flow used in investing activities | | $ | (2,845,157 | ) | | $ | (471,590 | ) | | $ | (2,590,096 | ) |
| Net cash flow provided by (used in) financing activities | | $ | 250,309 | | | $ | (799,861 | ) | | $ | (70,757 | ) |
| | | | | | | | | | | | | |
| 2007 | | | | | | | | | | | | |
| Net cash flow provided by operating activities | | $ | 1,807,769 | | | $ | 879,940 | | | $ | 2,559,770 | |
| Net cash flow used in investing activities | | $ | (1,238,487 | ) | | $ | (883,397 | ) | | $ | (2,117,731 | ) |
| Net cash flow provided by (used in) financing activities | | $ | (368,909 | ) | | $ | 47,705 | | | $ | (221,586 | ) |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| FINANCIAL POSITION INFORMATION |
| As of December 31, 2009 and 2008 |
| | | | | | | | | | | | | |
| | | Utility (a) | | | Non-Utility Nuclear | | Entergy Consolidated (a) | |
| | | (In Thousands) |
| 2009 | | | | | | | | | | | | |
| Current assets | | $ | 3,102,516 | | | $ | 2,625,482 | | | $ | 4,534,161 | |
| Other property and investments | | $ | 2,294,191 | | | $ | 3,229,677 | | | $ | 3,618,700 | |
| Property, plant and equipment - net | | $ | 19,253,914 | | | $ | 3,911,195 | | | $ | 23,389,402 | |
| Deferred debits and other assets | | $ | 5,044,111 | | | $ | 824,455 | | | $ | 5,822,334 | |
| Current liabilities | | $ | 2,678,278 | | | $ | 439,206 | | | $ | 3,193,997 | |
| Non-current liabilities | | $ | 19,756,470 | | | $ | 5,325,411 | | | $ | 25,245,897 | |
| Shareholders' equity | | $ | 7,073,474 | | | $ | 4,826,192 | | | $ | 8,707,360 | |
| | | | | | | | | | | | | |
| 2008 | | | | | | | | | | | | |
| Current assets | | $ | 3,067,301 | | | $ | 1,737,474 | | | $ | 5,160,389 | |
| Other property and investments | | $ | 2,089,231 | | | $ | 1,697,893 | | | $ | 3,237,544 | |
| Property, plant and equipment - net | | $ | 18,595,892 | | | $ | 3,592,359 | | | $ | 22,429,114 | |
| Deferred debits and other assets | | $ | 5,057,723 | | | $ | 820,469 | | | $ | 5,789,771 | |
| Current liabilities | | $ | 3,635,614 | | | $ | 318,082 | | | $ | 3,765,894 | |
| Non-current liabilities | | $ | 18,217,228 | | | $ | 3,359,490 | | | $ | 24,573,303 | |
| Shareholders' equity | | $ | 6,770,794 | | | $ | 4,170,623 | | | $ | 8,060,592 | |
| | | | | | | | | | | | | |
| (a) In addition to the two operating segments presented here, Entergy Consolidated also includes Entergy Corporation (parent company), other business activity, and intercompany eliminations, including the non-nuclear wholesale assets business and earnings on the proceeds of sales of previously-owned businesses. | |
| | | | | | | | | | | | |
2012 Compared to 2011
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2012 to 2011 showing how much the line item increased or (decreased) in comparison to the prior period.
| | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | | | Entergy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| 2011 Consolidated Net Income (Loss) | | $ | 1,123,866 | | | $ | 491,846 | | | $ | (248,340 | ) | | $ | 1,367,372 | |
| | | | | | | | | | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | | | 64,531 | | | | (191,311 | ) | | | (4,313 | ) | | | (131,093 | ) |
| Other operation and maintenance expenses | | | 128,955 | | | | 52,253 | | | | (3,574 | ) | | | 177,634 | |
| Asset impairment | | | - | | | | 355,524 | | | | - | | | | 355,524 | |
| Taxes other than income taxes | | | 803 | | | | 20,675 | | | | (206 | ) | | | 21,272 | |
| Depreciation and amortization | | | 45,728 | | | | (3,145 | ) | | | (200 | ) | | | 42,383 | |
| Other income | | | (458 | ) | | | 9,866 | | | | 3,885 | | | | 13,293 | |
| Interest expense | | | 20,746 | | | | (15,167 | ) | | | 50,078 | | | | 55,657 | |
| Other expenses | | | 9,356 | | | | (25,209 | ) | | | - | | | | (15,853 | ) |
| Income taxes | | | 22,029 | | | | (114,957 | ) | | | (162,480 | ) | | | (255,408 | ) |
| | | | | | | | | | | | | | | | | |
| 2012 Consolidated Net Income (Loss) | | $ | 960,322 | | | $ | 40,427 | | | $ | (132,386 | ) | | $ | 868,363 | |
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
In the fourth quarter 2012, Entergy moved two subsidiaries from Parent & Other to the Entergy Wholesale Commodities segment to improve the alignment of certain intercompany items and income tax activity. The prior period financial information in this Form 10-K has been restated to reflect this change.
As discussed in more detail in Note 1 to the financial statements, results of operations for 2012 include a $355.5 million ($223.5 million after-tax) impairment charge to write down the carrying values of Vermont Yankee and related assets to their fair values. Also, net income in 2012 was significantly affected by two settlements with the IRS; one of which related to the income tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs, and the other of which related to nuclear power plant decommissioning liabilities, both of which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2012, associated with the storm costs settlement to reflect the obligation to customers with respect to the settlement. See Note 3 to the financial statements for additional discussion of the tax settlements. Net income for Utility for 2011 was significantly affected by a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2011, because Entergy Louisiana is sharing the benefits with customers. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2012 to 2011.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 4,904 | |
| Mark-to-market tax settlement sharing | | | 200 | |
| Retail electric price | | | 81 | |
| Grand Gulf recovery | | | 71 | |
| Net wholesale revenue | | | (28 | ) |
| Purchased power capacity | | | (29 | ) |
| Volume/weather | | | (80 | ) |
| Louisiana Act 55 financing savings obligation | | | (161 | ) |
| Other | | | 11 | |
| 2012 net revenue | | $ | 4,969 | |
The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in September 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts with customers. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.
The retail electric price variance is primarily due to:
| · | an increase in the storm cost recovery rider at Entergy Mississippi, as approved by the MPSC for a five-month period effective August 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income; |
| · | an increase in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2012. This increase is offset by costs included in other operation and maintenance expenses and has no effect on net income; |
| · | a special formula rate plan rate increase at Entergy Louisiana effective May 2011 in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. See Note 2 to the financial statements for a discussion of the formula rate plan increase; and |
| · | base rate increases at Entergy Texas beginning May 2011 as a result of the settlement of the December 2009 rate case and effective July 2012 as a result of the PUCT’s order in the December 2011 rate case. See Note 2 to the financial statements for further discussion of the rate cases. |
These increases were partially offset by formula rate plan decreases at Entergy New Orleans effective October 2011 and at Entergy Gulf States Louisiana effective September 2012. See Note 2 to the financial statements for further discussion of the formula rate plan decreases.
The Grand Gulf recovery variance is primarily due to increased recovery of higher costs resulting from the Grand Gulf uprate.
The net wholesale revenue variance is primarily due to decreased sales volume to municipal and co-op customers and lower prices.
The purchased power capacity variance is primarily due to price increases for ongoing purchased power capacity and additional capacity purchases.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The volume/weather variance is primarily due to decreased electricity usage, including the effect of milder weather as compared to the prior period on residential and commercial sales. Hurricane Isaac, which hit the Utility’s service area in August 2012, also contributed to the decrease in electricity usage. Billed electricity usage decreased a total of 1,684 GWh, or 2%, across all customer classes.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge recorded in 2012 because Entergy Gulf States Louisiana and Entergy Louisiana are sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Note 3 to the financial statements for additional discussion of the tax settlement and savings obligation.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2012 to 2011.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 2,045 | |
| Nuclear realized price changes | | | (194 | ) |
| Nuclear volume | | | (33 | ) |
| Other | | | 36 | |
| 2012 net revenue | | $ | 1,854 | |
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $191 million, or 9%, in 2012 compared to 2011 primarily due to lower pricing in its contracts to sell power and lower volume in its nuclear fleet resulting from more unplanned and refueling outage days in 2012 as compared to 2011 which was partially offset by the exercise of resupply options provided for in purchase power agreements whereby Entergy Wholesale Commodities may elect to supply power from another source when the plant is not running. Amounts related to the exercise of resupply options are included in the GWh billed in the table below. Partially offsetting the lower net revenue from the nuclear fleet was higher net revenue from the Rhode Island State Energy Center, which was acquired in December 2011.
Following are key performance measures for Entergy Wholesale Commodities for 2012 and 2011.
| | | 2012 | | 2011 |
| | | | | |
| Owned capacity | | 6,612 | | 6,599 |
| GWh billed | | 46,178 | | 43,497 |
| Average realized price per MWh | | $50.02 | | $54.50 |
| | | | | |
| Entergy Wholesale Commodities Nuclear Fleet |
| Capacity factor | | 89% | | 93% |
| GWh billed | | 41,042 | | 40,918 |
| Average realized revenue per MWh | | $50.29 | | $54.73 |
| Refueling Outage Days: | | | | |
FitzPatrick | | 34 | | - |
Indian Point 2 | | 28 | | - |
Indian Point 3 | | - | | 30 |
Palisades | | 34 | | - |
Pilgrim | | - | | 25 |
Vermont Yankee | | - | | 25 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants
The recent economic downturn and negative trends in the energy commodity markets have resulted in lower natural gas prices and lower market prices for electricity in the New York and New England power regions, which is where five of the six Entergy Wholesale Commodities nuclear power plants are located. Entergy Wholesale Commodities’ nuclear business experienced a decrease in realized price per MWh to $50.29 in 2012 from $54.73 in 2011 and $59.16 in 2010, and is likely to experience a decrease again in 2013 because, as shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 85% of its planned nuclear energy output for 2013 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2012. In addition, Entergy Wholesale Commodities has sold forward 73% of its planned nuclear energy output for 2014 for an expected average contracted energy price of $45 per MWh based on market prices at December 31, 2012. Near-term prices present a challenging economic situation for the Entergy Wholesale Commodities plants. The challenge is greater for some of these plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the investment required to maintain the safety and integrity of the plants. If, in the future, economic conditions or regulatory activity no longer support the continued operation of a plant it could adversely affect Entergy’s results of operations through impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs. Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed below in “Critical Accounting Estimates.” See also the discussion below in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” regarding Entergy Wholesale Commodities nuclear plant operating license and related activity.
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $1,951 million for 2011 to $2,080 million for 2012 primarily due to:
| · | an increase of $47 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below and Note 11 to the financial statements for further discussion of benefits costs; |
| · | $38 million of costs incurred in 2012 related to the planned spin-off and merger of the Utility’s transmission business; |
| · | an increase of $29 million in nuclear expenses primarily due to higher labor costs, including higher contract labor; |
| · | an increase of $21 million resulting from a temporary increase in the Entergy Mississippi storm damage reserve authorized by the MPSC effective August 2012. These costs included are recovered through the storm cost recovery rider and have no effect on net income; |
| · | an increase of $14 million in energy efficiency costs at Entergy Arkansas. These costs are recovered through the energy efficiency rider and have no effect on net income; |
| · | the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’ 2010 test year formula rate plan filing approved by the City Council in September 2011. See Note 2 to the financial statements for further discussion of the Entergy New Orleans 2010 test year formula rate plan filing and settlement; and |
| · | an increase of $10 million in operating expenses due to the sale of surplus oil inventory in 2011. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
These increases were partially offset by:
| · | a decrease of approximately $7 million as a result of the deferral or capitalization of storm restoration costs for Hurricane Isaac, which hit the Utility’s service area in August 2012; |
| · | the effect of the deferral, as approved by the FERC, and the LPSC for the Louisiana jurisdictions, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $10 million; and |
| · | a decrease of $9 million in legal expenses, not including legal costs related to the transition and implementation of joining the MISO RTO and the planned spin-off and merger of the Utility’s transmission business which are included in other bullets, primarily resulting from a decrease in legal and regulatory activity decreasing the use of outside legal services. |
Depreciation and amortization expense increased primarily due to additions to plant in service.
Interest expense increased primarily due to a revision in 2011 caused by FERC’s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects. Also contributing to the increase were net debt issuances by certain of the Utility operating companies.
Entergy Wholesale Commodities
Other operation and maintenance expenses increased from $906 million for 2011 to $958 million for 2012 primarily due to:
| · | an increase of $23 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits " below and Note 11 to the financial statements for further discussion of benefits costs; |
| · | an increase of $23 million primarily due to higher contract labor costs and higher material and supply costs; and |
| · | an increase of $20 million due to the operations of the Rhode Island State Energy Center, which was acquired in December 2011. |
These increases were partially offset by the effects of recording the final court decisions in the Vermont Yankee and Indian Point 2 lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $25 million of spent nuclear fuel storage costs previously recorded as operation and maintenance expenses.
The asset impairment variance is due to a $355.5 million ($223.5 million after-tax) impairment charge recorded in the first quarter 2012 to write down the carrying values of Vermont Yankee and related assets to their fair values. See Note 1 to the financial statements for further discussion of this charge.
Taxes other than income taxes increased primarily due to increased property taxes at FitzPatrick, increased electric generating excises at Vermont Yankee, and property taxes from the Rhode Island State Energy Center acquired in December 2011. Previously, FitzPatrick was granted an exemption from property taxation and paid taxes according to a payment in lieu of property tax agreement. This agreement expired on June 30, 2011 and FitzPatrick is now being taxed under the regular property tax system. FitzPatrick has pending litigation in the Fifth Judicial District of New York State Supreme Court challenging each annual property tax assessment placed on FitzPatrick since the expiration of the payment in lieu of tax agreement. The State of Vermont enacted legislation, which became effective on July 1, 2012, increasing the electric generating excise on Vermont Yankee. Vermont Yankee is challenging the constitutionality of this legislation. In October 2012 the federal judge for the U.S. District Court for the District of Vermont dismissed the suit on jurisdictional grounds. In November 2012, Entergy appealed the District Court’s decision to the Second Circuit Court of Appeals, where the suit remains pending.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Depreciation and amortization expenses decreased primarily due to adjustments resulting from final court decisions in the Entergy Nuclear Indian Point 2 and Vermont Yankee lawsuits against the U.S. Department of Energy related to spent nuclear fuel disposal. The effects of recording the proceeds from the judgments reduced the plant in service balances with a corresponding $25 million reduction to previously-recorded depreciation expense. Partially offsetting the adjustment was an increase due to additions to plant in service, including the acquisition of the Rhode Island State Energy Center in December 2011.
Other expenses decreased primarily due to a credit to decommissioning expense of $49 million in the second quarter 2012 compared to a credit to decommissioning expense of $34 million in the fourth quarter 2011 resulting from reductions in the decommissioning cost liabilities for certain nuclear plants as a result of revised decommissioning cost studies. See “Critical Accounting Estimates – Nuclear Decommissioning Costs” below for further discussion of these credits.
Parent & Other
Interest expense increased primarily due to the issuance of $500 million of 4.7% senior notes by Entergy Corporation in January 2012 and a higher interest rate on outstanding borrowings under the Entergy Corporation credit facility.
Income Taxes
The effective income tax rate for 2012 was 3.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2012 is related to (1) an IRS settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax position related to that item as discussed further in Note 3 to the financial statements; (2) a unanimous court decision from the U.S. Court of Appeals for the Fifth Circuit affirming an earlier decision of the U.S. Tax Court holding that Entergy was entitled to claim a credit against its U.S. tax liability for the U.K. windfall tax that it paid. The decision necessitated that Entergy reverse the provision for the uncertain tax position related to that item; and (3) an IRS Settlement on nuclear power plant decommissioning liabilities resulting in an earnings benefit of approximately $155 million, as discussed further in Note 3 to the financial statements.
The effective income tax rate for 2011 was 17.3%. The difference in the effective income tax rate versus the statutory rate of 35% in 2011 was primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense of $422 million. See Note 3 to the financial statements for further discussion of the settlement.
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2011 Compared to 2010
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2011 to 2010 showing how much the line item increased or (decreased) in comparison to the prior period.
| | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | | | Entergy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| 2010 Consolidated Net Income (Loss) | | $ | 829,719 | | | $ | 450,104 | | | $ | (9,518 | ) | | $ | 1,270,305 | |
| | | | | | | | | | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | | | (146,947 | ) | | | (155,898 | ) | | | 3,620 | | | | (299,225 | ) |
| Other operation and maintenance expenses | | | 1,674 | | | | (141,672 | ) | | | 38,354 | | | | (101,644 | ) |
| Taxes other than income taxes | | | 248 | | | | 1,079 | | | | 400 | | | | 1,727 | |
| Depreciation and amortization | | | 16,326 | | | | 16,008 | | | | (26 | ) | | | 32,308 | |
| Gain on sale of business | | | - | | | | (44,173 | ) | | | - | | | | (44,173 | ) |
| Other income | | | (3,388 | ) | | | (47,257 | ) | | | 9,339 | | | | (41,306 | ) |
| Interest expense | | | (37,502 | ) | | | (69,661 | ) | | | 45,623 | | | | (61,540 | ) |
| Other expenses | | | 1,688 | | | | (23,335 | ) | | | 1 | | | | (21,646 | ) |
| Income taxes | | | (426,916 | ) | | | (71,489 | ) | | | 167,429 | | | | (330,976 | ) |
| | | | | | | | | | | | | | | | | |
| 2011 Consolidated Net Income (Loss) | | $ | 1,123,866 | | | $ | 491,846 | | | $ | (248,340 | ) | | $ | 1,367,372 | |
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompanies Entergy Corporation’s financial statements in this report for further information with respect to operating statistics.
Net income for Utility in 2011 was significantly affected by a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense. The net income effect was partially offset by a regulatory charge, which reduced net revenue in 2011, because a portion of the benefits will be shared with customers. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2011 to 2010.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 5,051 | |
| Mark-to-market tax settlement sharing | | | (196 | ) |
| Purchased power capacity | | | (21 | ) |
| Net wholesale revenue | | | (14 | ) |
| Volume/weather | | | 13 | |
| ANO decommissioning trust | | | 24 | |
| Retail electric price | | | 49 | |
| Other | | | (2 | ) |
| 2011 net revenue | | $ | 4,904 | |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The mark-to-market tax settlement sharing variance results from a regulatory charge because a portion of the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers, slightly offset by the amortization of a portion of that charge beginning in October 2011. See Notes 3 and 8 to the financial statements for additional discussion of the tax settlement and benefit sharing.
The purchased power capacity variance is primarily due to price increases for ongoing purchased power capacity and additional capacity purchases.
The net wholesale revenue variance is primarily due to lower margins on co-owner contracts and higher wholesale energy costs.
The volume/weather variance is primarily due to an increase of 2,061 GWh in weather-adjusted usage across all sectors. Weather-adjusted residential retail sales growth reflected an increase in the number of customers. Industrial sales growth has continued since the beginning of 2010. Entergy’s service territory has benefited from the national manufacturing economy and exports, as well as industrial facility expansions. Increases have been offset to some extent by declines in the paper, wood products, and pipeline segments. The increase was also partially offset by the effect of less favorable weather on residential sales.
The ANO decommissioning trust variance is primarily related to the deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment. The gains resulted in an increase in interest and investment income in 2010 and a corresponding increase in regulatory charges with no effect on net income.
The retail electric price variance is primarily due to:
| · | rate actions at Entergy Texas, including a base rate increase effective August 2010 and an additional increase beginning May 2011; |
| · | a formula rate plan increase at Entergy Louisiana effective May 2011; and |
| · | a base rate increase at Entergy Arkansas effective July 2010. |
These were partially offset by formula rate plan decreases at Entergy New Orleans effective October 2010 and October 2011. See Note 2 to the financial statements for further discussion of these proceedings.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2011 to 2010.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 2,200 | |
| Nuclear realized price changes | | | (159 | ) |
| Fuel expenses | | | (30 | ) |
| Harrison County | | | (27 | ) |
| Nuclear volume | | | 61 | |
| 2011 net revenue | | $ | 2,045 | |
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by $155 million, or 7%, in 2011 compared to 2010 primarily due to:
| · | lower pricing in its contracts to sell power; |
| · | higher fuel expenses, primarily at the nuclear plants; and |
| · | the absence of the Harrison County plant, which was sold in December 2010. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
These factors were partially offset by higher volume resulting from fewer planned and unplanned outage days in 2011 compared to the same period in 2010.
Following are key performance measures for Entergy Wholesale Commodities for 2011 and 2010:
| | | 2011 | | 2010 |
| | | | | |
| Owned capacity | | 6,599 | | 6,351 |
| GWh billed | | 43,497 | | 42,934 |
| Average realized price per MWh | | $54.50 | | $58.69 |
| | | | | |
| Entergy Wholesale Commodities Nuclear Fleet |
| Capacity factor | | 93% | | 90% |
| GWh billed | | 40,918 | | 39,655 |
| Average realized revenue per MWh | | $54.73 | | $59.16 |
| Refueling Outage Days: | | | | |
FitzPatrick | | - | | 35 |
Indian Point 2 | | - | | 33 |
Indian Point 3 | | 30 | | - |
Palisades | | - | | 26 |
Pilgrim | | 25 | | - |
Vermont Yankee | | 25 | | 29 |
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $1,949 million for 2010 to $1,951 million for 2011 primarily due to:
| · | an increase of $17 million in nuclear expenses primarily due to higher labor costs, including higher contract labor; |
| · | an increase of $15 million in contract costs due to the transition and implementation of joining the MISO RTO; |
| · | an increase of $9 million in legal expenses primarily resulting from an increase in legal and regulatory activity increasing the use of outside legal services; |
| · | an increase of $8 million in fossil-fueled generation expenses primarily due to the addition of Acadia Unit 2 in April 2011; and |
| · | several individually insignificant items. |
These increases were substantially offset by:
| · | a decrease of $29 million in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense. The decrease in stock option expense is offset by credits recorded by the parent company, Entergy Corporation; |
| · | the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’ 2010 test year formula rate plan filing approved by the City Council in September 2011. See Note 2 to the financial statements for further discussion of the 2010 test year formula rate plan filing and settlement; |
| · | the amortization of $11 million of Entergy Texas rate case expenses in 2010. See Note 2 to the financial statements for further discussion of the Entergy Texas rate case settlement; and |
| · | a decrease of $10 million in operating expenses due to the sale of surplus oil inventory in 2011. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Depreciation and amortization expense increased primarily due to an increase in plant in service, partially offset by a decrease in depreciation rates at Entergy Arkansas as a result of the rate case settlement agreement approved by the APSC in June 2010.
Interest expense decreased primarily due to:
| · | the refinancing of long-term debt at lower interest rates by certain of the Utility operating companies; |
| · | a revision caused by FERC’s acceptance of a change in the treatment of funds received from independent power producers for transmission interconnection projects; and |
| · | interest expense accrued in 2010 related to the expected result of the LPSC Staff audit of Entergy Gulf States Louisiana’s fuel adjustment clause for the period 1995 through 2004. |
Entergy Wholesale Commodities
Other operation and maintenance expenses decreased from $1,047 million for 2010 to $906 million for 2011 primarily due to:
| · | the write-off of $64 million of capital costs in 2010, primarily for software that would not be utilized, and $16 million of additional costs incurred in 2010 in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business; |
| · | a decrease of $30 million due to the absence of expenses from the Harrison County plant, which was sold in December 2010; |
| · | a decrease in compensation and benefits costs resulting from an increase of $19 million in the accrual for incentive-based compensation in 2010; |
| · | a decrease of $12 million in spending on tritium remediation work; and |
| · | the write-off of $10 million of capitalized engineering costs in 2010 associated with a potential uprate project. |
The gain on sale resulted from the sale in 2010 of Entergy’s ownership interest in the Harrison County Power Project 550 MW combined-cycle plant to two Texas electric cooperatives that owned a minority share of the plant. Entergy sold its 61 percent share of the plant for $219 million and realized a pre-tax gain of $44.2 million on the sale.
Depreciation and amortization expense increased primarily due to an increase in plant in service and declining useful life of nuclear assets.
Other income decreased primarily due to a decrease in interest income earned on loans to the parent company, Entergy Corporation, and a decrease of $13 million in realized earnings on decommissioning trust fund investments.
Interest expense decreased primarily due to the write-off of $39 million of debt financing costs in 2010, primarily incurred for a $1.2 billion credit facility that will not be used, in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business.
Other expenses decreased primarily due to a credit to decommissioning expense of $34 million in 2011 resulting from a reduction in the decommissioning liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. See “Critical Accounting Estimates – Nuclear Decommissioning Costs” below for further discussion of accounting for asset retirement obligations.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Parent & Other
Other operation and maintenance expenses increased primarily due to lower intercompany stock option credits recorded by the parent company, Entergy Corporation, and an increase of $13 million related to the planned spin-off and merger of Entergy’s transmission business. See “Plan to Spin Off the Utility’s Transmission Business” below for further discussion.
Interest expense increased primarily due to $1 billion of Entergy Corporation senior notes issued in September 2010, with the proceeds used to pay down borrowings outstanding on Entergy Corporation’s revolving credit facility that were at a lower interest rate.
Income Taxes
The effective income tax rate for 2011 was 17.3%. The difference in the effective income tax rate versus the statutory rate of 35% in 2011 was primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a reduction in income tax expense of $422 million. See Note 3 to the financial statements for further discussion of the settlement.
The effective income tax rate for 2010 was 32.7%. The difference in the effective income tax rate versus the statutory rate of 35% in 2010 was primarily due to:
| · | a favorable U.S. Tax Court decision holding that the U.K. Windfall Tax may be used as a credit for purposes of computing the U.S. foreign tax credit, which allowed Entergy to reverse a provision for uncertain tax positions of $43 million, included in Parent and Other, on the issue. See Note 3 to the financial statements for further discussion of this tax litigation; |
| · | a $19 million tax benefit recorded in connection with Entergy’s decision to unwind the infrastructure created for the planned spin-off of its non-utility nuclear business; and |
| · | the recognition of a $14 million Louisiana state income tax benefit related to storm cost financing. |
Partially offsetting the decreased effective income tax rate was a charge of $16 million resulting from a change in tax law associated with the recently enacted federal healthcare legislation, as discussed below in “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” and state income taxes and certain book and tax differences for Utility plant items.
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates, and for additional discussion regarding income taxes.
Plan to Spin Off the Utility’s Transmission Business
On December 5, 2011, Entergy announced that it would spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp. (ITC). In order to effect the spin-off and merger, Entergy entered into (i) a Merger Agreement with Mid South TransCo LLC, a newly formed, wholly-owned subsidiary of Entergy (TransCo); ITC; and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (Merger Sub), a newly formed, wholly-owned subsidiary of ITC; and (ii) a Separation Agreement with TransCo, ITC, each of the Utility operating companies, and Entergy Services, Inc. These agreements, which have been approved by the Boards of Directors of Entergy and ITC, provide for the separation of Entergy’s transmission business (the Transmission Business), the distribution to Entergy’s stockholders of all of the common units, excluding any common units to be contributed to an exchange trust in the event Entergy makes the exchange trust election described below, of TransCo, a holding company subsidiary formed to hold the Transmission Business, and the merger of Merger Sub with and into TransCo, with TransCo continuing as the surviving entity in the Merger (the Merger), following which each common unit of TransCo will be converted into the right to receive one fully paid and nonassessable share of ITC common stock. Both the Distribution (as defined below) and the Merger are expected to qualify as tax-free transactions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, Entergy will distribute the TransCo common units to its shareholders, excluding any TransCo common units to be contributed to an exchange trust in the event Entergy makes the exchange trust election described below. At Entergy’s election, it may distribute the TransCo common units by means of a pro rata dividend in a spin-off or pursuant to an exchange offer in a split-off, or a combination of a spin-off and a split-off (the Distribution). In connection with the Merger, ITC will effectuate a $700 million recapitalization, which will take the form of a one-time special dividend to its shareholders of record as of a record date prior to the Merger (the Special Dividend), a share repurchase or a combination thereof. The decision regarding the form of the recapitalization will be determined by the board of directors of ITC at a later date closer to the Merger. Entergy’s shareholders who become shareholders of ITC as a result of the Merger will not receive the Special Dividend. Pursuant to the Merger Agreement, and subject to the terms and conditions set forth therein, immediately after the consummation of the Separation (as defined below), the consummation of the Financings (as defined below), the payment of the Special Dividend and the consummation of the Distribution, Merger Sub will merge with and into TransCo, with TransCo continuing as the surviving entity, and Entergy shareholders who hold common units of TransCo will have those units exchanged for ITC common stock on a one-for-one basis. Consummation of the transactions contemplated by the Separation Agreement and the Merger Agreement is expected to result in Entergy’s shareholders, together with the exchange trust described below if it is utilized, holding at least 50.1% of ITC’s common stock and existing ITC shareholders holding no more than 49.9% of ITC’s common stock immediately after the Merger.
Pursuant to the Merger Agreement, Entergy may elect to retain up to the number of TransCo common units that would convert in the Merger into up to 4.9999% of the total number of shares of ITC common stock outstanding on a fully diluted basis immediately following the consummation of the Merger that otherwise would have been distributed in the Distribution (the Exchange Trust Election). If Entergy makes the Exchange Trust Election, Entergy will transfer the retained TransCo common units to an irrevocable trust (the Exchange Trust). The TransCo common units transferred to the Exchange Trust will not be distributed to the distribution agent on behalf of Entergy shareholders in the Distribution. At the closing of the Merger, the TransCo common units transferred to the Exchange Trust will convert to ITC common stock. The trustee of the Exchange Trust will own and hold legal title to the TransCo common units and, following consummation of the Merger, ITC common stock for the benefit of Entergy and Entergy shareholders; provided, however, in no event will the ITC common stock held by the Exchange Trust be transferred to Entergy. Upon delivery of notice by Entergy, the trustee of the Exchange Trust will conduct an exchange offer (the Exchange Trust Exchange Offer) pursuant to which Entergy shareholders may exchange Entergy common stock for the ITC common stock held by the Exchange Trust. Any ITC common stock remaining in the Exchange Trust after six months following the completion of the Merger will be distributed to Entergy shareholders pro rata. The purpose of the Exchange Trust is to permit an exchange offer with Entergy shareholders to occur during a period after the closing, when the trading market for the ITC common stock has settled following the Merger. The Exchange Trust Exchange Offer, if elected by Entergy, is an option to help Entergy efficiently manage its post-transaction capital structure and improve cash flow and credit metrics. Upon the consummation of a successful exchange offer by the Exchange Trust, there would be fewer outstanding shares of Entergy common stock, as those shares would have been exchanged for the shares of ITC common stock held by the Exchange Trust. Consequently, a successful delayed exchange offer would permit Entergy to reduce its common shares outstanding and aggregate cash dividends paid and as a result could improve Entergy’s available cash flow and credit metrics.
The Merger Agreement contains certain customary representations and warranties. The Merger Agreement may be terminated: (i) by mutual consent of Entergy and ITC, (ii) by either Entergy or ITC if the Merger has not been completed by June 30, 2013, subject to an up to six month extension by either Entergy or ITC in certain circumstances, (iii) by either Entergy or ITC if the transactions are enjoined or otherwise prohibited by applicable law, (iv) by Entergy, on the one hand, or ITC, on the other hand, upon a material breach of the Merger Agreement by the other party that has not been cured by the cure period specified in the Merger Agreement, (v) by either Entergy or ITC if ITC’s shareholders fail to approve the ITC shareholder proposals, (vi) by Entergy if the ITC Board of Directors withdraws or changes its recommendation of the ITC shareholder proposals in a manner adverse to Entergy, (vii) by Entergy if ITC willfully breaches in any material respect its non-solicitation covenant and the breach has not been cured by the cure period specified in the Merger Agreement, (viii) by Entergy if there is a law or order that enjoins the transactions or imposes a burdensome condition on Entergy, (ix) by either Entergy or ITC if there is a law or order that enjoins the transactions or imposes a
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
burdensome condition on ITC, (x) by ITC, prior to ITC shareholder approval, to enter into a transaction for a superior proposal, provided that ITC complies with its notice and other obligations in the non-solicitation provision and pays Entergy the termination fee concurrently with termination or (xi) by ITC if Entergy takes certain actions with respect to the migration of the Transmission Business to a regional transmission organization if such actions could reasonably be expected to have certain adverse effects on TransCo or ITC after the Merger. In the event that (i) ITC terminates the Merger Agreement to accept a superior acquisition proposal, (ii) Entergy terminates the Merger Agreement because the ITC Board of Directors has withdrawn its recommendation of the ITC shareholder proposals, approves or recommends another acquisition proposal, fails to reaffirm its recommendation or materially breaches the non-solicitation provisions, (iii) either of the parties terminates the Merger Agreement because the approval of ITC’s shareholders is not obtained or (iv) Entergy terminates because of ITC’s uncured willful breach of the Merger Agreement, and in the case of clauses (iii) and (iv) an ITC takeover transaction was publicly announced and not withdrawn prior to termination and within 12 months of termination ITC agrees to or consummates a takeover transaction, then ITC must pay Entergy a $113,570,800 termination fee.
Consummation of the Merger is subject to the satisfaction of customary closing conditions for a transaction such as the Merger, including, among others, (i) consummation of the Separation, the Distribution, the Financings and the Special Dividend, (ii) the approval of the ITC shareholder proposals by the shareholders of ITC, (iii) the authorization for listing on the New York Stock Exchange of ITC common stock to be issued in the Merger, (iv) the receipt by Entergy of regulatory approvals necessary to become a member of an acceptable regional transmission organization, (v) the receipt of regulatory approvals necessary to consummate the transaction and no such regulatory approvals impose a burdensome condition on ITC or Entergy, (vi) the expiration of the applicable waiting period under the Hart-Scott-Rodino Act (which has occurred), (vii) the absence of a material adverse effect on the Transmission Business or ITC, (viii) the receipt by Entergy of a solvency opinion and (ix) the receipt of a private letter ruling from the IRS substantially to the effect that certain requirements for the tax-free treatment of the distribution of TransCo are met and an opinion that the Distribution and the Merger will be treated as tax-free reorganizations for U.S. federal income tax purposes. The Merger and the other transactions contemplated by the Merger Agreement and the Separation Agreement are planned for completion in 2013.
Pursuant to the Separation Agreement, and subject to the terms and conditions set forth therein, Entergy will engage in a series of preliminary restructuring transactions that result in the transfer to TransCo’s subsidiaries of the assets relating to the Transmission Business (the Separation). TransCo and its subsidiaries will consummate certain financing transactions (the TransCo Financing) totaling approximately $1.775 billion (as may be adjusted pursuant to the Merger Agreement and the Separation Agreement) pursuant to which (i) TransCo’s subsidiaries will borrow through a funded bridge facility with a term of 366 days and (ii) TransCo will issue senior securities of TransCo to Entergy (the TransCo Securities). Neither Entergy nor the Utility operating companies will guarantee or otherwise be liable for the payment of the TransCo Securities after the Separation occurs. Entergy will issue new debt or enter into agreements under which certain unrelated creditors will agree to purchase existing corporate debt of Entergy, which will be exchangeable into the TransCo Securities at closing (the Exchangeable Debt Financing). Entergy intends to contribute some or all of the proceeds from the new debt to the Utility operating companies. In addition, prior to the closing TransCo and/or the TransCo subsidiaries may obtain a working capital revolving credit facility in a principal amount agreed to by Entergy and ITC (such financing, together with the TransCo Financing and the Exchangeable Debt Financing, the Financings).
Under the terms of the Separation Agreement, immediately prior to the closing, each Utility operating company will contribute its respective transmission assets to a subsidiary that will become a TransCo subsidiary in the Separation in exchange for the equity interest in that subsidiary and the net proceeds received by that subsidiary from the funded bridge facility described above. Each Utility operating company will distribute the equity interests in the subsidiaries holding the transmission assets to Entergy, which will then contribute such interests to TransCo. The Utility operating companies intend to apply all of the amounts received by them from the subsidiaries and from Entergy to the prepayment or redemption of outstanding preferred and debt securities, with
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
the goal, following showscompletion of the Separation, of maintaining their capitalization generally consistent with their capitalization prior to the Separation. Although the aggregate amount and particular series of preferred and debt securities of each Utility operating company to be redeemed as well as the redemption dates are uncertain at this time and are expected to remain subject to change, each Utility operating company currently anticipates that all of its outstanding preferred securities, if any are outstanding, will be redeemed or otherwise retired prior to the Separation and that debt securities in the following approximate aggregate amounts will be redeemed prior to or following the Separation: $.45 billion for Entergy Arkansas, $.25 billion for Entergy Gulf States Louisiana, $.33 billion for Entergy Louisiana, $.24 billion for Entergy Mississippi, $2.5 million for Entergy New Orleans, and $.28 billion for Entergy Texas. Entergy and the Utility operating companies may, subject to certain conditions, modify or supplement the manner in which the Separation is consummated. As of December 31, 2012, net transmission plant in service, which does not include transmission-related construction work in progress or general or intangible plant, for the Utility operating companies was $1.03 billion for Entergy Arkansas, $.57 billion for Entergy Gulf States Louisiana, $.73 billion for Entergy Louisiana, $.58 billion for Entergy Mississippi, $.03 billion for Entergy New Orleans, and $.64 billion for Entergy Texas. Consummation of the Separation is subject to the satisfaction of the conditions applicable to Entergy and ITC contained in the Separation Agreement and the Merger Agreement, including that the sum of the principal amount of TransCo Securities issued to Entergy and the principal amount of the bridge facility entered into by TransCo’s subsidiaries is approximately $1.775 billion, subject to adjustment pursuant to the Merger Agreement and affiliatesthe Separation Agreement.
Filings with Retail Regulators
In conjunction with ITC, each of the Utility operating companies has filed applications with their respective retail regulators seeking approval for the proposal to spin off and merge the Transmission Business with ITC, including approval for change of control of the transmission assets and transaction-related steps in the spin-off and merger. An application was filed with the LPSC on September 5, 2012, with the City Council on September 12, 2012, with the APSC on September 28, 2012, with the MPSC on October 5, 2012, and with the PUCT on February 19, 2013. Also, on February 22, 2013, Entergy Texas filed with the PUCT its transmission cost recovery rider application seeking to recover its 2014 ITC transmission charges and MISO administrative costs. Entergy Arkansas and ITC also filed a joint application with the Missouri Public Service Commission on February 14, 2013 to obtain approval for the transfer of limited transmission facilities located in Missouri.
The ALJ in the LPSC proceeding has established a procedural schedule with staff testimony due March 14, 2013 and a hearing set to commence on June 24, 2013. LPSC consideration is anticipated in September 2013. The City Council has established a procedural schedule with a hearing scheduled to commence on July 23, 2013, with certification of the record to the City Council no later than August 6, 2013. The APSC established a procedural schedule with staff testimony due in April 2013 and a hearing commencing in July 2013. The MPSC has established a procedural schedule with staff testimony due in June 2013, a hearing commencing in August 2013, and a final order issued on or before September 15, 2013. The PUCT is required to issue an order within Entergy's180 days of Entergy Texas’s filing.
Filings with the FERC
On September 24, 2012, Entergy, ITC, and certain of their subsidiaries submitted a series of filings with the FERC to obtain regulatory approvals related to the proposed transfer to ITC subsidiaries of the transmission assets owned by the Utility operating companies. These filings include a joint application for authorization of the acquisition and disposition of jurisdictional transmission facilities, approval of transmission service formula rates and certain jurisdictional agreements, and a petition for declaratory order on the application of Federal Power Act section 305(a). The application seeks approval under Federal Power Act section 205 of formula rates under Attachment O of the MISO Tariff for each of the new ITC Operating Companies (which will become Transmission Owner members of MISO) and of related jurisdictional pro forma agreements. In a separate filing, MISO sought approval of an amendment to the MISO Tariff pursuant to Federal Power Act section 205 to enable the integration of the new ITC Operating Companies’ transmission facilities into MISO prior to the Utility operating companies becoming market participants in MISO. On September 26, 2012, Entergy Services submitted an application under Federal Power Act section 205 requesting FERC authorization to cancel System Agreement Service Schedule MSS-2 (Transmission Equalization) effective upon closing of the transaction. In October 2012, Entergy, ITC, and certain subsidiaries submitted filings with the FERC to obtain regulatory approvals under Federal Power Act section 204 for the various financings being undertaken as part of the transaction.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Various parties have submitted comments and protests to the FERC regarding these filings. The comments filed at the FERC include various matters related to the proposed transaction itself, including concerns about hold harmless commitments, whether the benefits of the transaction outweigh rate effects, and whether the transaction is consistent with the public interest, as well as issues related to the Utility operating companies’ proposal to join MISO. Commenters have also challenged, among other things, aspects of the transmission rates proposed by the ITC applicants, including for example the proposed return on common equity, debt/equity ratio, and the number of transmission pricing zones. Entergy and ITC are in the process of responding to the comments and protests filed as of a January 22, 2013 comment deadline established by the FERC. FERC rules call for a decision 180 days from the date of a completed application provided that the matter is not set for hearing or is not otherwise extended for up to an additional 180 days. If a matter is set for hearing, a procedural schedule will be established.
Other Filings
In July 2012, Entergy Corporation submitted a request to the Internal Revenue Service seeking a private letter ruling substantially to the effect that certain requirements for the tax-free treatment of the distribution of the transmission business segments. Companiesare met. In September 2012, Entergy submitted an application to the NRC for approval of certain nuclear plant license transfers and amendments as part of the steps to complete the spin-off and merger. In December 2012, Entergy submitted a pre-merger notification under the Hart-Scott-Rodino Act (HSR Act) with the Federal Trade Commission and the Department of Justice and the applicable waiting period under the HSR Act has expired.
Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants
In March 2011 and May 2012 the NRC renewed the operating licenses of Vermont Yankee and Pilgrim, respectively, for an additional 20 years, as a result of which each license now expires in 2032. For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. In the Vermont Yankee license renewal case, the Vermont Department of Public Service and the New England Coalition appealed the NRC’s renewal of Vermont Yankee’s license to the D.C. Circuit. In June 2012 the D.C. Circuit denied that fileappeal. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired. In the Pilgrim license renewal case, three contentions remained pending before the ASLB at the time the license was issued. Two of those contentions were subsequently denied by the ASLB and not appealed within the applicable time. A third remaining contention (alleging failure of the Pilgrim Environmental Impact Statement to address adequately an endangered species) was denied by the ASLB and then appealed to the NRC, which denied the appeal on December 6, 2012. No appeal of the NRC’s decision was filed within the time allowed for such appeals. The NRC has indicated that should the appeal of a contention result in voiding of the renewed license, Pilgrim could operate under the “timely renewal” doctrine in reliance on the prior, and now superseded, license until proceedings concerning the renewed license are final. Massachusetts appealed the NRC’s renewal of Pilgrim’s license to the United States Court of Appeals for the First Circuit. Entergy intervened in that appeal. Briefing was completed and oral argument was held December 5, 2012. On February 25, 2013, the United States Court of Appeals for the First Circuit denied Massachusetts’s appeal.
The NRC operating licenses for Indian Point 2 and Indian Point 3 expire in September 2013 and December 2015, respectively, and NRC license renewal applications are in process for these plants. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. Various parties have expressed opposition to renewal of the licenses. In April 2007, Entergy submitted the application to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years. The ASLB has admitted 21 contentions raised by the State of New York or other parties, which were combined into 16 discrete issues. Three of the issues have been resolved, and 13 issues remain
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
subject to ASLB resolution. In July 2011, the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the Final Supplemental Environmental Impact Statement (FSEIS) (discussed below). That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident. In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC staff to explain why cost-beneficial SAMAs should not be required to be implemented. Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it. In December 2011, the NRC denied Entergy’s appeal as premature, stating that the appeal could be renewed at the conclusion of the ASLB proceedings.
Pursuant to ASLB scheduling orders in the Indian Point 2 and 3 license renewal proceeding, hearings on the nine contentions remaining in “Track 1” were held over 12 days in October, November, and December 2012. Testimony on the four contentions currently in “Track 2” has not been completed. Track 2 hearings have not been scheduled.
The NRC staff is also continuing to perform its technical and environmental reviews of the Indian Point 2 and 3 license renewal application. The NRC staff issued a Final Safety Evaluation Report (FSER) in August 2009, a supplement to the FSER in August 2011, a FSEIS in December 2010 and a supplement to the FSEIS in June 2012. The NRC staff issued a draft supplemental FSEIS in June 2012 and has stated its intent to issue, following an opportunity for comment, another supplement to the FSEIS by April 30, 2013. In addition, the NRC staff has stated its intent to issue a further supplement to the FSER by July 31, 2013. These reports are expected to affect testimony yet to be filed on Track 2 contentions.
The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing process as permitted by the NRC’s hearing rules. As noted in Entergy’s responses to the various intervenor filings, Entergy believes the contentions proposed by the intervenors are unsupported and without merit. Entergy will continue to work with the NRC staff as it completes its technical and environmental reviews of the Indian Point 2 and 3 license renewal applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and the timing of license renewals.
The New York State Department of Environmental Conservation has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Entergy submitted its application for a water quality certification to the NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. After Entergy submitted certain additional information in response to NYSDEC requests for additional information, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification application was complete. In April 2010 the NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. The NYSDEC staff decision does not restrict Indian Point operations, but the issuance of a certification is potentially required prior to NRC issuance of renewed unit licenses. In June 2011, Entergy filed notice with the NRC that the NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, has taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, has waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act. The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a certification. The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues. The judge held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in October 2011, which is continuing into 2013. After the full hearing on the merits, the ALJs will issue a recommended decision to the Commissioner who will then issue the final agency decision. A party to the proceeding can appeal the decision of the Commissioner to state court.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the consistency of Indian Point’s operations with New York State’s coastal management policies must be resolved to the extent required by the Coastal Zone Management Act (CZMA). On July 24, 2012, Entergy filed a supplement to the Indian Point license renewal application currently pending before the NRC. The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC may issue the requested renewed operating licenses for Indian Point without the need for an additional consistency review by the State of New York under the CZMA. On July 30, 2012, Entergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses. Responses to Entergy’s motion for declaratory order are due March 22, 2013. In addition, Entergy filed with the New York State Department of State (NYSDOS) on November 7, 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review. The NYSDOS denied the motion by order dated January 9, 2013. An appeal may be taken to state court within four months. Finally, on December 17, 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies. Entergy included in the consistency determination a “reservation of rights” clarifying that Entergy does not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. On January 16, 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it does not include the further supplement to the FSEIS that, as indicated above, is targeted for issuance by April 30, 2013. The six-month federal deadline for state decision on a consistency determination does not begin to run until the submission is complete.
The NRC operating license for Palisades expires in 2031 and for FitzPatrick expires in 2034.
Liquidity and Capital Resources
This section discusses Entergy’s capital structure, capital spending plans and other information withuses of capital, sources of capital, and the SEC undercash flow activity presented in the Securities Exchange Act of 1934 are identifiedcash flow statement.
Capital Structure
Entergy’s capitalization is balanced between equity and debt, as shown in bold-faced type.the following table.
| | | 2012 | | 2011 |
| | | | | |
| Debt to capital | | 58.7% | | 57.3% |
| Effect of excluding securitization bonds | | (1.8%) | | (2.3%) |
| Debt to capital, excluding securitization bonds (1) | | 56.9% | | 55.0% |
| Effect of subtracting cash | | (1.1%) | | (1.5%) |
| Net debt to net capital, excluding securitization bonds (1) | | 55.8% | | 53.5% |
| (1) | Calculation excludes the Arkansas, Louisiana, and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, and Entergy Texas, respectively. |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, common shareholders’ equity, and subsidiaries’ preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. Entergy uses the net debt to net capital ratio and the ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy’s financial condition.
Long-term debt, including the currently maturing portion, makes up most of Entergy’s total debt outstanding. Following are Entergy’s long-term debt principal maturities and estimated interest payments as of December 31, 2012. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2012. The amounts below include payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Long-term debt maturities and estimated interest payments | | 2013 | | 2014 | | 2015 | | 2016-2017 | | after 2017 |
| | | (In Millions) |
| | | | | | | | | | | |
| Utility | | $1,194 | | $904 | | $816 | | $1,540 | | $12,186 |
| Entergy Wholesale Commodities | | 15 | | 15 | | 18 | | 4 | | 57 |
| Parent and Other | | 83 | | 83 | | 627 | | 1,385 | | 512 |
| Total | | $1,292 | | $1,002 | | $1,461 | | $2,929 | | $12,755 |
Note 5 to the financial statements provides more detail concerning long-term debt outstanding.
Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in March 2017. Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit facility. The commitment fee is currently 0.275% of the commitment amount. Commitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 2012 was 2.04% on the drawn portion of the facility.
As of December 31, 2012, amounts outstanding and capacity available under the $3.5 billion credit facility are:
Capacity | | Borrowings | | Letters of Credit | | Capacity Available |
| (In Millions) |
| | | | | | | |
| $3,500 | | $795 | | $8 | | $2,697 |
A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio of 65% or less of its total capitalization. The calculation of this debt ratio under Entergy Corporation’s credit facility is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with the covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility’s maturity date may occur.
In September 2012, Entergy Corporation implemented a commercial paper program with a program limit of up to $500 million. In November 2012, Entergy Corporation increased the limit for the commercial paper program to $1 billion. At December 31, 2012, Entergy Corporation had $665 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2012 was 0.88%.
Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
| | 2013 | | 2014 | | 2015 | | 2016-2017 | | after 2017 | |
| | (In Millions) |
| | | | | | | | | | | |
| Capital lease payments | $6 | | $5 | | $5 | | $9 | | $34 | |
The capital leases are discussed in Note 10 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 2012 as follows.
Company | | Entergy Corporation
Expiration Date | | |
Amount of Facility | | Interest Rate (a) | | | | | | | |
| | | | | | | | | |
| | | | | | | | | Amount Drawn as of Dec. 31, 2012 |
| | | | | | | | | |
UtilityEntergy Arkansas | | Non-Utility NuclearApril 2013 | | Other Businesses$20 million (b) | | 1.81% | | - |
| Entergy Arkansas | | March 2017 | | $150 million (c) | | 1.71% | | - |
| Entergy Gulf States Louisiana | | March 2017 | | $150 million (d) | | 1.71% | | - |
| Entergy Louisiana | | March 2017 | | $200 million (e) | | 1.71% | | - |
| Entergy Mississippi | | May 2013 | | $35 million (f) | | 1.96% | | - |
| Entergy Mississippi | | May 2013 | | $25 million (f) | | 1.96% | | - |
| Entergy Mississippi | | May 2013 | | $10 million (f) | | 1.96% | | - |
| Entergy New Orleans | | November 2013 | | $25 million (g) | | 1.69% | | - |
| Entergy Texas | | March 2017 | | $150 million (f) | | 1.96% | | - |
| (a) | The interest rate is the weighted average interest rate as of December 31, 2012 applied, or that would be applied, to outstanding borrowings under the facility. |
| (b) | The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization. Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable. |
| (c) | The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
| (d) | The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
| (e) | The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
| (f) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable. Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
| (g) | The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization. |
| (h) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement, securitization bonds are excluded from debt and capitalization in calculating the debt ratio. |
Operating Lease Obligations and Guarantees of Unconsolidated Obligations
Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy’s guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy’s financial condition, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 2012 on non-cancelable operating leases with a term over one year.
| | 2013 | | 2014 | | 2015 | | 2016-2017 | | after 2017 | |
| | (In Millions) |
| | | | | | | | | | | |
| Operating lease payments | $94 | | $97 | | $80 | | $94 | | $140 | |
The operating leases are discussed in Note 10 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Summary of Contractual Obligations of Consolidated Entities
| Contractual Obligations | | 2013 | | 2014-2015 | | 2016-2017 | | after 2017 | | Total |
| | | (In Millions) |
| | | | | | | | | | | |
| Long-term debt (1) | | $1,292 | | $2,463 | | $2,929 | | $12,755 | | $19,439 |
| Capital lease payments (2) | | $6 | | $10 | | $9 | | $34 | | $59 |
| Operating leases (2) | | $94 | | $177 | | $94 | | $140 | | $505 |
| Purchase obligations (3) | | $1,939 | | $3,512 | | $2,609 | | $11,195 | | $19,255 |
| (1) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (2) | Lease obligations are discussed in Note 10 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations. |
In addition to the contractual obligations, Entergy currently expects to contribute approximately $163.3 million to its pension plans and approximately $82.5 million to other postretirement plans in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy has $148 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
| · | maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt); |
| · | permit the continued commercial operation of Grand Gulf; |
| · | pay in full all System Energy indebtedness for borrowed money when due; and |
| · | enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy’s rights in the agreement as security for the specific debt. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Capital Expenditure Plans and Other Uses of Capital
Following are the amounts of Entergy’s planned construction and other capital investments by operating segment for 2013 through 2015.
| Planned construction and capital investments | | 2013 | | 2014 | | 2015 |
| | | | (In Millions) |
| | | | | | | | |
| Maintenance Capital: | | | | | | |
| | Utility: | | | | | | |
| | Generation | | $133 | | $127 | | $135 |
| | Transmission | | 253 | | 229 | | 202 |
| | Distribution | | 504 | | 494 | | 489 |
| | Other | | 97 | | 107 | | 105 |
| | Total | | 987 | | 957 | | 931 |
| | Entergy Wholesale Commodities | | 108 | | 131 | | 176 |
| | | | $1,095 | | $1,088 | | $1,107 |
| Capital Commitments: | | | | | | |
| | Utility: | | | | | | |
| | Generation | | $716 | | $415 | | $392 |
| | Transmission | | 162 | | 240 | | 303 |
| | Distribution | | 45 | | 21 | | 16 |
| | Other | | 92 | | 88 | | 92 |
| | Total | | 1,015 | | 764 | | 803 |
| | Entergy Wholesale Commodities | | 257 | | 242 | | 281 |
| | | | 1,272 | | 1,006 | | 1,084 |
| Total | | $2,367 | | $2,094 | | $2,191 |
The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development.
Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth, and includes spending for the nuclear and non-nuclear plants at Entergy Wholesale Commodities.
Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts reflected in this category include the following.
| · | The currently planned construction or purchase of additional generation supply sources within the Utility’s service territory through the Utility’s portfolio transformation strategy, including a self-build option at Entergy Louisiana’s Ninemile site identified in the Summer 2009 Request for Proposal and final spending from the Waterford 3 steam generator replacement project, both of which are discussed below. |
| · | Spending to support the Utility’s plan to join the MISO RTO by December 2013 along with other transmission projects. |
| · | Entergy Wholesale Commodities investments associated with specific investments such as dry cask storage, nuclear license renewal, component replacement and identified repairs, and potential wedgewire screens at Indian Point. |
| · | Environmental compliance spending. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis and the implementation of new environmental laws and regulations. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The Utility’s owned generating capacity remains short of customer demand, and its supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, changes in project plans, and the ability to access capital.
Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. All major permits and approvals required to begin construction have been obtained and construction is in progress.
Under the terms approved by the LPSC, costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans, if one is in effect when the project is placed in service; alternatively, Entergy Gulf States Louisiana and Entergy Louisiana must file rate cases approximately 12 months prior to the expected in-service date. Entergy New Orleans is expected to file a full rate case 12 months prior to the expected in-service date.
Waterford 3 Steam Generator Replacement Project
Entergy Louisiana planned to replace the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, in the spring 2011. Replacement of these components is common to pressurized water reactors throughout the nuclear industry. In December 2010, Entergy Louisiana advised the LPSC that the replacement generators would not be completed and delivered by the manufacturer in time to install them during the spring 2011 refueling outage. During the final steps in the manufacturing process, the manufacturer discovered separation of stainless steel cladding from the carbon steel base metal in the channel head of both replacement steam generators (RSGs), in areas beneath and adjacent to the divider plate. As a result of this damage, the manufacturer was unable to meet the contractual delivery deadlines, and the RSGs were not installed in the spring 2011. Waterford 3 resumed operations with the original steam generators upon completion of the spring 2011 refueling outage, which included inspection and maintenance of the original steam generators.
Entergy Louisiana worked with the RSG manufacturer to fully develop, evaluate, and implement repair options, and the RSGs were delivered in time for Waterford 3’s fall 2012 refueling outage, which began in October 2012. During the fall 2012 refueling outage Entergy Louisiana replaced the RSGs, reactor vessel head, and control element drive mechanisms. Those components, which together comprised the replacement project, were placed in-service in December 2012.
In June 2008, Entergy Louisiana filed with the LPSC for approval of the replacement project, including full cost recovery. Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding. The LPSC unanimously approved the settlement in November 2008. The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2)
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Management's Financial Discussion and Analysis
the decision to undertake the replacement project at the then-estimated cost is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extension or renewal of the formula rate plan or in a full base rate case including necessary pro forma adjustments.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan and provided a mechanism to begin recovering the costs of the replacement project in the first billing cycle after it is placed in service. On December 21, 2012, Entergy Louisiana provided notice of the first year revenue requirement associated with the replacement project that would be placed into rates in the January 2013 billing cycle. The estimated revenue requirement included the LPSC-jurisdictional share of the replacement project costs, less (i) a credit for earnings above a 10.25% return on common equity (based on the 2011 test year) for the period following the in-service date, and (ii) a credit for operation and maintenance savings expected from the RSGs. These rates are anticipated to remain in effect until Entergy Louisiana’s rate case filed in February 2013 is resolved. See Note 2 to the financial statements for additional discussion of the formula rate plan and rate case filings. With completion of the replacement project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
Dividends and Stock Repurchases
Declarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings, financial strength, and future investment opportunities. At its January 2013 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy has paid since the second quarter 2010. The prior quarterly dividend per share was $0.75. Entergy paid $589 million in 2012, $590 million in 2011, and $604 million in 2010 in cash dividends on its common stock.
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans.
In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2009 the Board granted authority for a $750 million share repurchase program which was completed in the fourth quarter 2010. In October 2010 the Board granted authority for an additional $500 million share repurchase program. As of December 31, 2012, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.
Sources of Capital
Entergy’s sources to meet its capital requirements and to fund potential investments include:
| · | internally generated funds; |
| · | cash on hand ($533 million as of December 31, 2012); |
| · | bank financing under new or existing facilities or commercial paper; and |
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Management's Financial Discussion and Analysis
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2012, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.
The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively). No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 31, 2013. Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through July 2013. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2014. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.
In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.
In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to portions of Entergy's service territories in Louisiana and Texas, and to a lesser extent in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4
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Management's Financial Discussion and Analysis
million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. See Notes 2 and 3 to the financial statements for additional discussion of the Act 55 financings.
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. There is no recourse to Entergy or Entergy Arkansas in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.
Entergy Louisiana Securitization Bonds – Little Gypsy
In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. There is no recourse to Entergy or Entergy Louisiana in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the investment recovery bonds.
Cash Flow Activity
As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 694 | | | $ | 1,295 | | | $ | 1,710 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 2,940 | | | | 3,128 | | | | 3,926 | |
| Investing activities | | | (3,639 | ) | | | (3,447 | ) | | | (2,574 | ) |
| Financing activities | | | 538 | | | | (282 | ) | | | (1,767 | ) |
| Net decrease in cash and cash equivalents | | | (161 | ) | | | (601 | ) | | | (415 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 533 | | | $ | 694 | | | $ | 1,295 | |
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Management's Financial Discussion and Analysis
Operating Activities
2012 Compared to 2011
Entergy's net cash provided by operating activities decreased by $188 million in 2012 compared to 2011 primarily due to:
| · | the decrease in Entergy Wholesale Commodities net revenue that is discussed previously; |
| · | Hurricane Isaac storm restoration spending in 2012; |
| · | income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; and |
| · | a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order. |
These decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
2011 Compared to 2010
Entergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane Gustav and Hurricane Ike. The Act 55 storm cost financings are discussed in Note 2 to the financial statements. The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.
Investing Activities
2012 Compared to 2011
Net cash used in investing activities increased by $192 million in 2012 compared to 2011 primarily due to an increase in construction expenditures, primarily in the Utility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012. Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital” above.
This increase was partially offset by:
| · | a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements; |
| · | proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and |
| · | a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. |
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Management's Financial Discussion and Analysis
2011 Compared to 2010
Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to:
| · | the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010. These transactions are described in more detail in Note 15 to the financial statements; |
| · | an increase in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and |
| · | a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas. The capital cost of repairing that damage was approximately $55 million. |
These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.
Financing Activities
2012 Compared to 2011
Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:
| · | long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility; |
| · | Entergy repurchasing $235 million of its common stock in 2011, as discussed below; |
| · | a net increase in 2012 of $51 million in short-term borrowings by the nuclear fuel company variable interest entities; and |
| · | $51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests. |
For the details of Entergy's commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. For the details of Entergy’s long-term debt outstanding, see Note 5 to the financial statements.
2011 Compared to 2010
Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010. The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million. For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements. In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010. Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
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Management's Financial Discussion and Analysis
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Company | | Authorized Return on Common Equity |
| | | |
Entergy Arkansas | | 10.2% | | |
| | | |
| Entergy Arkansas, Inc.Gulf States Louisiana | | | Entergy Nuclear Operations, Inc. | | | Entergy-Koch, LP | | | Non-Nuclear Wholesale Assets9.9%-11.4% Electric; 10.0%-11.0% Gas |
| EGS Holdings, Inc. | | | Entergy Nuclear Finance, LLC | | | (50% ownership) (liquidated December 2009) | | | |
| Entergy Gulf States Louisiana L.L.C. | | 9.45% - 11.05% | Entergy Nuclear Generation Co. (Pilgrim) | | | | |
| | | |
| Entergy Louisiana Holdings, IncMississippi | | | Entergy Nuclear FitzPatrick LLC | | | | | | | Entergy Asset Management, Inc.9.88% - 12.01% |
| Entergy Louisiana, LLC | | | Entergy Nuclear Indian Point 2, LLC | | | | | | | Entergy Power, Inc. |
| Entergy Mississippi, Inc. | | | Entergy Nuclear Indian Point 3, LLC | | | | | | | |
| Entergy New Orleans Inc. | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas | Entergy Nuclear Palisades, LLC | | | |
| | | |
| Entergy Texas Inc. | | | Entergy Nuclear Vermont Yankee, LLC | | | | | | |
| System Energy Resources, Inc. | | | Entergy Nuclear, Inc. | | | | | |
| Entergy Operations, Inc. | | | Entergy Nuclear Fuels Company | | | | | | | |
| Entergy Services, Inc. | | | Entergy Nuclear Nebraska LLC | | | | |
| System Fuels, Inc. | | | Entergy Nuclear Power Marketing LLC | | | | 9.8% |
StrategyThe Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Independent Coordinator of Transmission
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs. In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the ICT did not transfer control of the Entergy transmission system to the ICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
| · | granting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
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| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
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Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement Participation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
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Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy aspiresTexas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to achieve industry-leading total shareholder returnstransfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in an environmentally responsible fashionthe public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by leveraging the scalePUCT and expertise inherent inagreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its core nuclear and utility operations. Entergy's scope includes electricity generation, transmission and distributionnotice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as natural gas transportationEntergy Corporation and distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency,Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and risk management.their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy also focuses on portfolio managementTexas to make periodic buy, build, hold, or sell decisions based upon its analytically-derived pointsexit the System Agreement prior to the end of view, which are updated as market conditions evolve.the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
AvailabilityIn December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of SEC filingsEntergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. |
The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for 2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $163.3 million in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's websiteplans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy electronically files reportsmust comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies,environment. Entergy conducts studies to determine the extent of any required remediation and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC's Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operationhas recorded reserves based upon its evaluation of the Public Reference Roomlikelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov. Additionally, information about Entergy, including its reports filed with the SEC, is available without charge through its website, http://www.entergy.com. Reports filed with the SEC are available as soon as reasonably practicable after they are filed electronically with the SEC. Entergy uses its website to disclose important information to investors. Entergy is providing the address to its Internet site solely for the information of investors. Entergy does not intend the address to be an active linkfollowing external events or to otherwise incorporate the contents of the website into this report.conditions.
Part I, Item 1| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority. |
Litigation
Entergy is continuedregularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Uncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on page 194.several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENTDividends and Stock Repurchases
ManagementDeclarations of dividends on Entergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy’s common stock dividends based upon Entergy’s earnings, financial strength, and future investment opportunities. At its January 2013 meeting, the Board declared a dividend of $0.83 per share, which is the same quarterly dividend per share that Entergy Corporationhas paid since the second quarter 2010. The prior quarterly dividend per share was $0.75. Entergy paid $589 million in 2012, $590 million in 2011, and $604 million in 2010 in cash dividends on its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.common stock.
In accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted unit awards to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management assesses the effectiveness of Entergy's internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forthhas been authorized by the CommitteeBoard to repurchase on the open market shares up to an amount sufficient to fund the exercise of Sponsoring Organizationsgrants under the plans.
In addition to the authority to fund grant exercises, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2009 the Board granted authority for a $750 million share repurchase program which was completed in the fourth quarter 2010. In October 2010 the Board granted authority for an additional $500 million share repurchase program. As of December 31, 2012, $350 million of authority remains under the Treadway Commission (COSO)$500 million share repurchase program. The amount of repurchases may vary as a result of material changes in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherentbusiness results or capital spending or new investment opportunities, or if limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.in the credit markets continue for a prolonged period.
Sources of Capital
Entergy CorporationEntergy’s sources to meet its capital requirements and the Registrant Subsidiaries' independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy's internal control over financial reporting as of December 31, 2009, which is included herein on pages 402 through 409.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management's assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2009. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy's and each of the Registrant Subsidiaries' financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
J. WAYNE LEONARD
Chairman of the Board and Chief Executive Officer of Entergy Corporation
| LEO P. DENAULT
Executive Vice President and Chief Financial Officer of Entergy Corporation
|
HUGH T. MCDONALD
Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc.
| E. RENAE CONLEY
Chair of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC
|
HALEY R. FISACKERLY
Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc.
| RODERICK K. WEST
Chairman, President, and Chief Executive Officer of Entergy New Orleans, Inc.
|
JOSEPH F. DOMINO
Chairman of the Board, President, and Chief Executive Officer of Entergy Texas, Inc.
| JOHN T. HERRON
Chairman, President, and Chief Executive Officer of System Energy Resources, Inc.
|
THEODORE H. BUNTING, JR.
Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc.
| WANDA C. CURRY
Vice President and Chief Financial Officer of System Energy Resources, Inc.
|
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Entergy operates primarily through two business segments: Utility and Non-Utility Nuclear.fund potential investments include:
| · | Utility generates, transmits, distributes, and sells electric power in service territories in four states that include portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business.
internally generated funds; |
| · | cash on hand ($533 million as of December 31, 2012); |
| · | bank financing under new or existing facilities or commercial paper; and operates six nuclear power plants located |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2012, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million and $68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.
The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively). No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 31, 2013. Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through July 2013. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2015. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2014. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed the FERC-authorized limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.
In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.
In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to portions of Entergy's service territories in Louisiana and Texas, and to a lesser extent in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. See Notes 2 and 3 to the financial statements for additional discussion of the Act 55 financings.
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. There is no recourse to Entergy or Entergy Arkansas in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.
Entergy Louisiana Securitization Bonds – Little Gypsy
In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. There is no recourse to Entergy or Entergy Louisiana in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the investment recovery bonds.
Cash Flow Activity
As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 694 | | | $ | 1,295 | | | $ | 1,710 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 2,940 | | | | 3,128 | | | | 3,926 | |
| Investing activities | | | (3,639 | ) | | | (3,447 | ) | | | (2,574 | ) |
| Financing activities | | | 538 | | | | (282 | ) | | | (1,767 | ) |
| Net decrease in cash and cash equivalents | | | (161 | ) | | | (601 | ) | | | (415 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 533 | | | $ | 694 | | | $ | 1,295 | |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Operating Activities
2012 Compared to 2011
Entergy's net cash provided by operating activities decreased by $188 million in 2012 compared to 2011 primarily due to:
| · | the decrease in Entergy Wholesale Commodities net revenue that is discussed previously; |
| · | Hurricane Isaac storm restoration spending in 2012; |
| · | income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; and |
| · | a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the northern United States and sellsrough production cost equalization payments previously collected. See Note 2 to the electric power produced by those plants primarily to wholesale customers. This business also provides services to other nuclear power plant owners.financial statements for further discussion of the FERC order. |
In additionThese decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
2011 Compared to its two primary, reportable, operating segments, Entergy also operates the non-nuclear wholesale assets business. The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view.2010
FollowingEntergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane Gustav and Hurricane Ike. The Act 55 storm cost financings are discussed in Note 2 to the percentages of Entergy's consolidated revenues andfinancial statements. The decrease in Entergy Wholesale Commodities net income generated by itsrevenue that is discussed above also contributed to the decrease in operating segments and the percentage of total assets held by them:cash flow.
| | | % of Revenue | | % of Net Income | | % of Total Assets |
| Segment | | 2009 | | 2008 | | 2007 | | 2009 | | 2008 | | 2007 | | 2009 | | 2008 | | 2007 |
| | | | | | | | | | | | | | | | | | | |
| Utility | | 75 | | 79 | | 80 | | 57 | | 49 | | 61 | | 80 | | 77 | | 78 |
| Non-Utility Nuclear | | 24 | | 19 | | 18 | | 50 | | 64 | | 46 | | 28 | | 21 | | 21 |
Parent Company & Other Business Segments | | 1 | | 2 | | 2 | | (7) | | (13) | | (7) | | (8) | | 2 | | 1 |
Plan2012 Compared to Pursue Separation of Non-Utility Nuclear2011
In November 2007,Net cash used in investing activities increased by $192 million in 2012 compared to 2011 primarily due to an increase in construction expenditures, primarily in the Board approved a plan to pursue a separationUtility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012. Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of the Non-Utility Nuclear business from Entergy through a tax-free spin-off of the Non-Utility Nuclear business to Entergy shareholders. Upon completion of the Board-approved spin-off plan, Enexus Energy Corporation, a wholly-owned subsidiary of Entergy, would be a new, separate, and publicly-traded company. In addition, under the plan, Enexus and Entergy are expected to enter into a nuclear services business joint venture, EquaGen LLC, with 50% ownership by Enexus and 50% ownership by Entergy. The EquaGen board of managers would be comprised of equal membership from both Entergy and Enexus.Capital” above.
This increase was partially offset by:
Once the spin-off transaction is complete, Entergy Corporation's shareholders will own all Entergy common stock and will receive a distribution of 80.1 percent of the Enexus common shares. Entergy will transfer the remaining Enexus common shares to a trust. While held by the trust, the Enexus common shares will be voted by the trustee in the same proportion as the other Enexus common shares on any matter submitted to a vote of the Enexus shareholders. Within a period of up to 18 months after the spin-off, Entergy is expected to exchange the Enexus common shares retained in the trust for Entergy common shares. Enexus common shares not ultimately exchanged, if any, will be distributed to Entergy shareholders.| · | a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements; |
| · | proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and |
Enexus' business would be substantially comprised of Non-Utility Nuclear's assets, including its six nuclear power plants, and Non-Utility Nuclear's power marketing operation. Entergy Corporation's remaining business would primarily be comprised of the Utility business. EquaGen would operate the nuclear assets owned by Enexus under the Board-approved plan, and provide certain services to the Utility's nuclear operations. EquaGen would also be expected to offer nuclear services to third parties, including decommissioning, plant relicensing, plant operations, and ancillary services.| · | a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2011 Compared to 2010
Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to:
| · | the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010. These transactions are described in more detail in Note 15 to the financial statements; |
| · | an increase in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and |
| · | a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas. The capital cost of repairing that damage was approximately $55 million. |
These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.
Financing Activities
2012 Compared to 2011
Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:
| · | long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility; |
| · | Entergy repurchasing $235 million of its common stock in 2011, as discussed below; |
| · | a net increase in 2012 of $51 million in short-term borrowings by the nuclear fuel company variable interest entities; and |
| · | $51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests. |
For the details of Entergy's commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. For the details of Entergy’s long-term debt outstanding, see Note 5 to the financial statements.
2011 Compared to 2010
Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010. The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million. For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements. In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010. Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Company | | Authorized Return on Common Equity |
| | |
Entergy Arkansas | | 10.2% |
| | |
| Entergy Gulf States Louisiana | | 9.9%-11.4% Electric; 10.0%-11.0% Gas |
| | |
Entergy Louisiana | | 9.45% - 11.05% |
| | |
| Entergy Mississippi | | 9.88% - 12.01% |
| | |
| Entergy New Orleans | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas |
| | |
Entergy Texas | | 9.8% |
The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Independent Coordinator of Transmission
In connection with2000 the spin-off, EnexusFERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs. In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is currently expected to incur up to $4.0 billion of debt prior to completionnot an RTO under FERC Order No. 2000 and installation of the spin-off. Currently,ICT did not transfer control of the debt is expectedEntergy transmission system to be incurred in the following transactions:ICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
| · | Enexus is expectedgranting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to issue upthe customer requesting or causing an upgrade to $2.0 billion of debt securities in partial consideration of Entergy's transfer to itbe constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | overseeing the operation of the Non-Utility Nuclearweekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement Participation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | These debt securities are expected to be exchanged for up to $2.0 billion of debt securities that Entergy plans to issue priorThe interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the spin-off. If the exchange occurs, the holders of the debt securities that Entergy plans to issue prior to the spin-off would become holders of up to $2.0 billion of Enexus debt securities.financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | Enexus is expectedThe interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to issue upthe financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to $2.0 billiontotal capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt securities directly to third party investors.outstanding. |
OutThe Utility business has limited exposure to the effects of existing cashmarket risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on handliquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the proceeds Enexussubsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would receiveincrease by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the issuanceMarch 2011 earthquake and tsunami, the NRC established a task force to conduct a review of debt securities directlyprocesses and regulations relating to third party investors, it expectsnuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to retain approximately $750 million, which it intends to use for workingundertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and other general corporate purposes. In addition, Enexus is expected to apply up to $500 millionan estimate of the proceeds from the issuance of these debt securities to provide cash collateral as credit support for reimbursement obligations in respect of letters of credit. All of the remaining proceeds, plus any remaining cash on hand, are expected toincreased costs cannot be transferred to Entergy to settle Enexus' intercompany indebtedness owed to Entergy, including indebtedness that Entergy will transfer to Enexus in the spin-off, and to purchase certain assets from Entergy. Enexus will not receive any proceeds from eithermade at this time.
With the issuance of the upthree orders, the NRC also provided members of the public an opportunity to $2.0 billionrequest a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its debt securities orhearing request and the exchangeNRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its debt securitiesWaste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy debt securities. Entergy expectsCorporation and Subsidiaries
Management's Financial Discussion and Analysis
National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to useaddress some of the proceedsissues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it receives fromwill not issue final licenses dependent upon the issuanceWaste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its debt securities to reduce outstanding Entergy debt.estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The amount torevised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be paid to Entergy,depreciated over the amount and termremaining life of the debt Enexus would incur, andunit.
In the typesecond quarter 2012, Entergy Wholesale Commodities recorded a reduction of debt and entity that would incur$60.6 million in the debt have not been finally determined, but would be determined priorestimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the spin-off. A numberexcess of factors could affect this final determination, andthe reduction in the liability over the amount of debt ultimately incurred could be different from the amount disclosed.
Enexus executed a $1.175 billion credit facility in December 2008. In October 2009, Enexus executed Amendment No. 1 to its credit facility, increasing the total credit facility amount to $1.2 billion from $1.175 billion. Enexus is not permitted to draw down the facility until certain customary and transactional conditions related to the spin-off are met on or prior to July 1, 2010. Enexus may enter into other financing arrangements meant to support Enexus' working capital and general corporate needs and credit support obligations arising from hedging and normal course of business requirements.undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and Enexus intenda credit to launchdecommissioning expense of $34.1 million, reflecting the financing relating to the spin-off after requisite regulatory approvals are received and when market conditions are favorable for such an issuance. Entergy expects the transaction to qualify for tax-free treatment for U.S. federal income tax purposes for both Entergy and its shareholders. Entergy received a private letter ruling from the IRS regarding certain requirements for tax-free treatment. In addition, a supplemental ruling request has been filed with the IRS to reflect changes to the initial spin-off plan. Final termsexcess of the transaction and spin-off completion are subject to several conditions, includingreduction in the final approvalliability over the amount of the Board.undepreciated assets.
Regulatory Proceedings Regarding the Spin-Off
NRC
Entergy Nuclear Operations, Inc., the current NRC-licensed operator of the Non-Utility Nuclear plants, filed an application in July 2007 with the NRC seeking indirect transfer of control of the operating licenses for the six Non-Utility Nuclear power plants, and supplemented that application in December 2007 to incorporate the planned business separation. Entergy Nuclear Operations, Inc., which is expected to be wholly-owned by EquaGen, would remain the operator of the plants after the spin-off. Entergy Operations, Inc., the current NRC-licensed operator of Entergy's five Utility nuclear plants, would remain a wholly-owned subsidiary of Entergy and would continue to be the operator of the Utility nuclear plants. In the December 2007 supplement to the NRC application, Entergy Nuclear Operations, Inc. provided additional information regarding the spin-off transaction, organizational structure, technical and financial qualifications, and general corporate information. On July 28, 2008, the NRC staff approved the license transfers associated with the proposed new ownership structure of EquaGen, the proposed licensed operator, as well as the transfers to Enexus of the ownership of Big Rock Point, FitzPatrick, Indian Point Units 1, 2
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and 3, Palisades, Pilgrim, and Vermont Yankee. The approval for the proposed new ownership structure is now effective until August 1, 2010. The review conducted by the NRC staff prior to approval of the license and ownership transfers included matters such as the financial and technical qualifications of the new organizations, as well as decommissioning funding assurance. In connection with the NRC approvals, Enexus agreed to enter into a financial support agreement with the entities that own the nuclear power plants in the total amount of $700 million to provide financial support, if needed, for the operating costs of the six operating Non-Utility Nuclear power plants.
FERCUnbilled Revenue
Pursuant to Federal Power Act section 203,As discussed in February 2008 an application was filed with the FERC requesting approval for the indirect disposition and transfer of control of jurisdictional facilities of a public utility. The FERC issued an order in June 2008 authorizing the requested indirect disposition and transfer of control. In August 2009 an amended application was filed with the FERC to reflect the transferNote 1 to the exchange trust byfinancial statements, Entergy records an estimate of the 19.9 percentrevenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of Enexus' common stock shares. In September 2009 the FERC approvedunbilled receivable at the amended application.beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
VermontImpairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
On January 28, 2008, Entergy NuclearFor additional discussion regarding the continued operation of the Vermont Yankee LLC and Entergy Nuclear Operations, Inc. requested approval from the Vermont Public Service Board (VPSB) for the indirect transferplant, see “Impairment of control, consent to pledge assets, issue guarantees and assign material contracts, amendment to certificate of public good, and replacement of guaranty and substitution of a credit support agreement for Vermont Yankee. Several parties intervenedLong-Lived Assets” in the proceeding. Discovery has been completed in this proceeding, in which parties could ask questions about or request the production of documents relatedNote 1 to the transaction.financial statements.
In addition, the Vermont Department of Public Service (VDPS), which is the public advocate in proceedings before the VPSB, prefiled its initial and rebuttal testimony in the case in which the VDPS took the position that Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. have not demonstrated that the restructuring promotes the public good because its benefits do not outweigh the risks, raising concerns that the target rating for Enexus' debt is below investment grade and that the company may not have the financial capability to withstand adverse financial developments, such as an extended outage. The VDPS testimony also expressed concern about the EquaGen joint venture structure and Enexus' ability, under the operating agreement between Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc., to ensure that Vermont Yankee is well-operated. Two distribution utilities that buy Vermont Yankee power prefiled testimony that also expressed concerns about the structure but found that there was a small net benefit to the restructuring. The VPSB conducted hearings on July 28-30, 2008, during which it considered the testimony prefiled by Entergy Nuclear Vermont Yankee, Entergy Nuclear Operations, Inc., the VDPS, and the two distribution utilities. Subsequently, Entergy Nuclear Operations, Inc. supplied supplemental data to the VPSB outlining the enhanced transaction structure detailed in the amended petition filed in New York (discussed below). On October 8, 2009, a memorandum of understanding was filed with the VPSB outlining an agreement reached with the VDPS, which, if approved by the VPSB, would result in approval of the spin-off transaction in Vermont.
In connection with this memorandum of understanding, Enexus agreed to provide a $100 million working capital facility to Entergy Nuclear Vermont Yankee and to obtain a $60 million letter of credit to fund operating expenses after operations cease at Vermont Yankee. In addition, Enexus agreed that if it has not obtained a credit rating of one notch below investment grade (e.g., a rating of BB+ by S&P) or higher by January 1, 2014, then Enexus will furnish to Entergy Nuclear Vermont Yankee a second letter of credit in the amount of $50 million to support Vermont Yankee's operations, which must be from a financial institution with a rating of A or higher from S&P, or in the alternative, a financial institution with a similar rating from a nationally respected credit rating agency that is of similar and appropriate credit quality. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations have prefiled testimony explaining this memorandum of understanding and updating the VPSB on the financial structure of the transactions and moved to amend their petition to include Enexus. To assist the VPSB in making its determinations and deciding what, if any, further proceedings are needed, the VPSB, on November 20, 2009, issued information requests to the three companies and to the VDPS. The companies filed their responses on December 9, 2009 and the VDPS filed its responses on December 24, 2009. A VPSB decision on the memorandum of understanding is pending.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
On January 27, 2010, Vermont Governor Jim Douglas issuedEntergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a statement directingdebt security has suffered an other-than-temporary impairment is based on whether Entergy has the Commissionerintent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the VDPSdebt security, an other-than-temporary-impairment is considered to requesthave occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a staynumber of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the VPSBrecognition of the spin-off proceedings pending an ongoing investigation relatingother-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to elevated levels of tritium found in Vermont Yankee groundwater monitoring wells. The Governor's statement further indicated that he would not ask the Vermont General Assembly to consider Vermont Yankee license renewal during its 2010 session. The governor's statement also expressed concerns about potential decommissioning costs and about inconsistent information related to underground piping at Vermont Yankee carrying radionuclides that was provided by Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. in a proceeding before the VPSB related to extending operation of Vermont Yankee beyond its current operating license. On February 3, 2010, the VDPS staff filed its motion for a stay of the spin-off proceedings. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. filed a memorandum in opposition to the request for a stay with the VPSB on February 18, 2010.
New York
On January 28, 2008, Entergy Nuclear FitzPatrick, LLC, Entergy Nuclear Indian Point 2, LLC, Entergy Nuclear Indian Point 3, LLC, Entergy Nuclear Operations, Inc., and Enexus filed a petition with the New York Public Service Commission (NYPSC) requesting a declaratory ruling regarding corporate reorganization or in the alternative an order approving the transaction and an order approving debt financing. Petitioners also requested confirmation that the corporate reorganization will not have an effect on Entergy Nuclear FitzPatrick's, Entergy Nuclear Indian Point 2's, Entergy Nuclear Indian Point 3's, and Entergy Nuclear Operations, Inc.'s status as lightly regulated entities in New York, given that they will continue to be competitive wholesale generators. The New York State Attorney General's Office, Westchester County, and other intervenors filed objections to the business separation and to the transfer of the FitzPatrick and Indian Point Energy Center nuclear power plants, arguing that the debt associated with the spin-off could threaten access to adequate financial resources for those nuclear power plants and because the New York State Attorney General's Office believes Entergy must file an environmental impact statement assessing the proposed corporate restructuring. In addition to the New York State Attorney General's Office, several other parties also requested to be added to the service list for this proceeding.
On May 23, 2008, the NYPSC issued its Order Establishing Further Procedures in this matter. In the order, the NYPSC determined that due to the nuclear power plants' unique role in supporting the reliability of electric service in New York, and their large size and unique operational concerns, a more searching inquiry of the transaction will be conducted than if other types of lightly-regulated generation were at issue. Accordingly, the NYPSC assigned an ALJ to preside over this proceeding and prescribed a sixty (60) day discovery period. The order provided that after at least sixty (60) days, the ALJ would establish when the discovery period would conclude. The NYPSC stated that the scope of discovery will be tightly bounded by the public interest inquiry relevant to this proceeding; namely, adequacy and security of support for the decommissioning of the New York nuclear facilities; financial sufficiency of the proposed capital structure in supporting continued operation of the facilities; and, arrangements for managing, operating and maintaining the facilities. The NYPSC also stated that during the discovery period, the NYPSC Staff may conduct technical conferences to assist in the development of a full record in this proceeding.
On July 23, 2008, the ALJs issued a ruling concerning discovery and seeking comments on a proposed process and schedule. In the ruling, the ALJs proposed a process for completing a limited, prescribed discovery process, to be followed three weeks later by the filing of initial comments addressing defined issues, with reply comments due two weeks after the initial comment deadline. Following receipt of all comments, a ruling will be made on whether, and to what extent, an evidentiary hearing is required. The ALJs asked the parties to address three specific topic areas: (1) the financial impacts related to the specific issues previously outlined by the NYPSC; (2) other obligations associated with the arrangement for managing, operating and maintaining the facilities; and (3) the extent that New York Power Authority (NYPA) revenuesthen current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from value sharing payments under2007 through 2010. As a result of the value sharing2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
agreements betweenIn selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and NYPA would decrease.matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The ALJs have indicateddiscount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the potential financial effecttarget asset allocation adjust dynamically over time, based on the funded status of the terminationplan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the value sharing payments on NYPA and New York electric consumers are factors the ALJs believe should be considered by the NYPSC in making its public interest determination.plan is 105% funded.
In August 2008, Non-Utility Nuclear enteredThe current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into a resolution of a dispute with NYPA over the applicability of the value sharing agreements to the FitzPatrick and Indian Point 3 nuclear power plants after the spin-off. Under the resolution, Non-Utility Nuclear agreed not to treat the separation as a "Cessation Event"account asset allocation adjustments that would terminate its obligation to make the payments under the value sharing agreements. As a result, after the spin-off, Enexus would continue to be obligated to make payments to NYPA due under the amended and restated value sharing agreements described above. For further discussion of the value sharing agreements, see Note 15 to the financial statements herein.were made during 2012.
In August 2009, Enexus filed withEntergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the NYPSC an amended petitionexpected long term rate of return was 6.5% for an order approving the reorganization2012, 5.5% for 2011 and associated debt financings. The amended petition describes proposed enhancements to the corporate reorganization. These proposed enhancements include a commitment to reserve at least $350 million of liquidity, a $1.0 billion reduction2010, and will be 6.5% in long-term bonds to $3.5 billion, an increase in the initial cash balance left at Enexus to $750 million from the original $250 million, and obtaining an up to $500 million cash-collateralized letter of credit facility that will provide letters of credit for commodity-related and non-hedging-related commercial transactions. The amended petition requested that the NYPSC: issue an order approving the corporate reorganization and associated financings; confirm the corporate reorganization will have no impact on the Enexus companies' status as lightly regulated entities; and issue a negative declaration and undertake no further review under the New York State Environmental Quality Review Act.2013.
On August 21, 2009, the ALJs issued a Ruling Concerning Scope, Process, and Schedule that determined that additional record development was warranted in light of the changes contained in the amended petition. The August 21, 2009 ruling limited the issues requiring further record development to environmental significance under the New York State Environmental Quality Review Act and whether Enexus will be at least as capable as Entergy in meeting all financial and other obligations related to the ownership and operation of the New York nuclear facilities. In early November 2009 the New York State Attorney General's Office, the New York Department of Public Service's Staff, and Westchester County filed initial comments on the amended petition stating their opposition to Enexus' request in the amended petition. Various filings continued to be made into January 2010 in accordance with the procedures and schedule ordered by the ALJs, and the New York State Attorney General's Office, the New York Department of Public Service's Staff, and Westchester County continue to oppose the transaction.
At a hearing on February 11, 2010, the NYPSC discussed Entergy's petition and issued a press release later that same day. The press release states, in part, that the NYPSC "received a report from senior Staff of the Department of Public Service (Staff) addressing a petition submitted by Entergy Corporation.... In its report, Staff concluded that the transaction, as proposed, was not in the public interest, and Staff provided the [NYPSC] information regarding the implications of rejecting the proposal versus making changes to the proposed transaction to improve the long-term financial stability of the three nuclear power plants in New York and to provide ratepayer benefits. The [NYPSC] will consider these topics in more detail at a later date. Staff concluded that the proposed transaction was problematic because the amount of debt leverage employed to finance Enexus is excessive when the business risks of this new merchant nuclear plant enterprise are considered. The principles behind the conditions proposed by Staff are to assure the immediate financial viability of Enexus by mitigating near-term liquidity risk related to debt covenants through a reduction of $550 million in the debt issued by Enexus, to assure the Enexus’s [sic] long-term financial capabilities through the maintenance of a specified bond rating or ratio of debt-to-equity market value, and to provide New York ratepayers some of the potential hedging benefits of nuclear power in periods of rising commodity prices. If the [NYPSC] decides to impose these conditions, or similar conditions addressing the previously stated principles, it is expected that the [NYPSC] will consider the comments of interested parties. Comments would then be analyzed and the matter brought back for final deliberations at the earliest possible [NYPSC] session."
The NYPSC currently has meetings scheduled for March 4 and March 25, 2010 at which it may consider the proposed transaction again.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2009 Compared to 2008
Following are income statement variances for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing 2009 to 2008 showing how much the line item increased or (decreased) in comparison to the prior period:Contents
| | | Utility | | Non-Utility Nuclear | | Parent & Other | | Entergy |
| | | (In Thousands) |
| | | | | | | | | |
| 2008 Consolidated Net Income (Loss) | | $605,144 | | $797,280 | | ($161,889) | | $1,240,535 |
| | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | | | | | | | | |
| Other operation and maintenance expenses | | (30,423) | | 76,007 | | (37,536) | | 8,048 |
| Taxes other than income taxes | | (2,173) | | 8,379 | | 701 | | 6,907 |
| Depreciation and amortization | | 37,409 | | 14,832 | | (326) | | 51,915 |
| Other income | | 74,456 | | 18,243 | | (92,278) | | 421 |
| Interest charges | | 36,990 | | 1,958 | | (77,425) | | (38,477) |
| Other | | 16,658 | | 12,542 | | 5 | | 29,205 |
| Income taxes | | 17,401 | | 60,159 | | (47,818) | | 29,742 |
| | | | | | | | | |
| 2009 Consolidated Net Income (Loss) | | $708,905 | | $631,020 | | ($88,875) | | $1,251,050 |
Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES" which accompanies Entergy Corporation's financial statements in this report for further information with respect to operating statistics.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2009 to 2008.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $4,589 |
Volume/weather | | 57 |
Retail electric price | | 33 |
Fuel recovery | | 31 |
Provision for regulatory proceedings | | (26) |
Other | | 10 |
2009 net revenue | | $4,694 |
The volume/weather variance is primarily due to increased electricity usage primarily during the unbilled sales period in addition to the negative effect of Hurricane Gustav and Hurricane Ike in 2008. Electricity usage by industrial customers decreased, however, by 6%. The overall decline of the economy led to lower usage affecting both the large customer industrial segment as well as small and mid-sized industrial customers, who are also being affected by overseas competition. The effect of the industrial sales volume decrease is mitigated, however, by the fixed charge basis of many industrial customers' rates, which causes average price per KWh sold to increase as the fixed charges are spread over lower volume.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The retail electric price increase is primarily due to:
· | rate increases that were implemented at Entergy Texas in January 2009; |
· | an increase in the formula rate plan rider at Entergy Gulf States Louisiana and Entergy Louisiana effective September 2008 and November 2009; |
· | the recovery of 2008 extraordinary storm costs at Entergy Arkansas as approved by the APSC, effective January 2009. The recovery of 2008 extraordinary storm costs is discussed in Note 2 to the financial statements; |
· | an increase in the capacity acquisition rider related to the Ouachita plant acquisition at Entergy Arkansas. The net income effect of the Ouachita plant cost recovery is limited to a portion representing an allowed return on equity with the remainder offset by Ouachita plant costs in other operation and maintenance expenses, depreciation expenses and taxes other than income taxes; |
· | an increase in the formula rate plan rider at Entergy Mississippi in July 2009; |
· | an Energy Efficiency rider at Entergy Texas, which was effective December 31, 2008, that is substantially offset in other operation and maintenance expenses; and |
· | an increase in the Attala power plant costs recovered through the power management rider by Entergy Mississippi. The net income effect of this recovery is limited to a portion representing an allowed return on equity with the remainder offset by Attala power plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes. |
The retail electric price increase was partially offset by:
· | a credit passed on to Louisiana retail customers as a result of the Act 55 storm cost financings that began in the third quarter of 2008; |
· | a formula rate plan refund of $16.6 million to customers in November 2009 in accordance with a settlement approved by the LPSC. See Note 2 to the financial statements for further discussion of the settlement; and |
· | a net decrease in the formula rate plans effective August 2008 at Entergy Louisiana and Entergy Gulf States Louisiana to remove interim storm cost recovery upon the Act 55 financing of storm costs as well as the storm damage accrual. A portion of the decrease is offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the formula rate plans. |
The fuel recovery variance resulted primarily from an adjustment to deferred fuel costs in the fourth quarter 2009 relating to unrecovered nuclear fuel costs incurred since January 2008 that will now be recovered after a revision to the fuel adjustment clause methodology.
The provision for regulatory proceedings variance is primarily due to provisions recorded in 2009 at Entergy Arkansas. See Note 2 to the financial statements for a discussion of regulatory proceedings affecting Entergy Arkansas.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Non-Utility Nuclear
Following is an analysis of the change in net revenue comparing 2009 to 2008.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $2,334 |
Volume variance | | (53) |
Palisades purchased power amortization | | (23) |
Realized price changes | | 67 |
Other | | (2) |
2009 net revenue | | $2,323 |
As shown in the table above, net revenue for Non-Utility Nuclear decreased slightly by $11 million, or 0.5%, in 2009 compared to 2008. Higher pricing in its contracts to sell power was partially offset by lower volume resulting from more refueling outage days in 2009 compared to 2008. Included in net revenue is $53 million and $76 million of amortization of the Palisades purchased power agreement in 2009 and 2008, respectively, which is non-cash revenue and is discussed in Note 15 to the financial statements. Following are key performance measures for 2009 and 2008:
| | | 2009 | | 2008 |
| | | | | |
| Net MW in operation at December 31 | | 4,998 | | 4,998 |
| Average realized price per MWh | | $61.07 | | $59.51 |
| GWh billed | | 40,981 | | 41,710 |
| Capacity factor | | 93% | | 95% |
| Refueling Outage Days: | | | | |
FitzPatrick | | - | | 26 |
Indian Point 2 | | - | | 26 |
Indian Point 3 | | 36 | | - |
Palisades | | 41 | | - |
Pilgrim | | 31 | | - |
Vermont Yankee | | - | | 22 |
Realized Price per MWh
When Non-Utility Nuclear acquired its six nuclear power plants it also entered into purchased power agreements with each of the sellers. For four of the plants, the 688 MW Pilgrim, 838 MW FitzPatrick, 1,028 MW Indian Point 2, and 1,041 MW Indian Point 3 plants, the original purchased power agreements with the sellers expired in 2004. The purchased power agreement with the seller of the 605 MW Vermont Yankee plant extends into 2012, and the purchased power agreement with the seller of the 798 MW Palisades plant extends into 2022. Market prices in the New York and New England power markets, where the four plants with original purchased power agreements that expired in 2004 are located, increased since the purchase of these plants, and the contracts that Non-Utility Nuclear entered into after the original contracts expired, as well as realized day ahead and spot market sales, have generally been at higher prices than the original contracts. Non-Utility Nuclear's annual average realized price per MWh increased from $39.40 for 2003 to $61.07 for 2009. Power prices increased in the period from 2003 through 2008 primarily because of increases in the price of natural gas. Natural gas prices increased in the period from 2003 through 2008 primarily
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
becauseCost Sensitivity
The following chart reflects the sensitivity of rising production costsqualified pension cost and limited importsqualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of liquefied natural gas, both caused by global demandpostretirement benefit cost and increasesaccumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the price of crude oil. In addition, increases in the price of power during this period were caused secondarily by rising heat rates, which in turn were caused primarily by load growth outpacing new unit additions. The majorityother components of the existing long-term contracts for power from these four plants expire by the end of 2012. The recent economic downturn and negative trends in the energy commodity markets have resulted in lower natural gas prices and therefore current prevailing market prices for electricity in the New York and New England power regionscalculation are generally below the prices in Non-Utility Nuclear's existing contracts in those regions. Therefore, it is uncertain whether Non-Utility Nuclear will continue to experience increases in its annual realized price per MWh or what contract prices for power Non-Utility Nuclear will be able to obtain as its existing long-term contracts expire. As shown in the contracted sale of energy table in "Market and Credit Risk Sensitive Instruments," Non-Utility Nuclear has sold forward 88% of its planned energy output in 2010 for an average contracted energy price of $57 per MWh.held constant.
Other Income Statement Items
Utility
Other operation and maintenance expenses decreased from $1,867 million for 2008 to $1,837 million for 2009. The variance includes the following:
· | a decrease due to the write-off in the fourth quarter 2008 of $52 million of costs previously accumulated in Entergy Arkansas's storm reserve and $16 million of removal costs associated with the termination of a lease, both in connection with the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas's base rate case. The base rate case is discussed in more detail in Note 2 to the financial statements; |
· | a decrease due to the capitalization of Ouachita plant service charges of $12.5 million previously expensed; |
· | a decrease of $22 million in loss reserves in 2009, including a decrease in storm damage reserves as a result of the completion of the Act 55 storm cost financing at Entergy Gulf States Louisiana and Entergy Louisiana; |
· | a decrease of $16 million in payroll-related and benefits costs; |
· | prior year storm damage charges as a result of several storms hitting Entergy Arkansas' service territory in 2008, including Hurricane Gustav and Hurricane Ike in the third quarter 2008. Entergy Arkansas discontinued regulatory storm reserve accounting beginning July 2007 as a result of the APSC order issued in Entergy Arkansas' rate case. As a result, non-capital storm expenses of $41 million were charged to other operation and maintenance expenses. In December 2008, $19.4 million of these storm expenses were deferred per an APSC order and were recovered through revenues in 2009; |
· | an increase of $35 million in fossil expenses primarily due to higher plant maintenance costs and plant outages; |
· | an increase of $22 million in nuclear expenses primarily due to increased nuclear labor and contract costs; |
· | an increase of $14 million due to the reinstatement of storm reserve accounting at Entergy Arkansas effective January 2009; |
· | an increase of $14 million due to the Hurricane Ike and Hurricane Gustav storm cost recovery settlement agreement, as discussed below under "Liquidity and Capital Resources - Sources of Capital - Hurricane Gustav and Hurricane Ike";
|
· | an increase of $8 million in customer service costs primarily as a result of write-offs of uncollectible customer accounts; and |
· | a reimbursement of $7 million of costs in 2008 in connection with a litigation settlement. |
Accounting Mechanisms
Depreciation and amortization expenses increased primarily dueAccounting standards require an employer to an increaserecognize in plant in service.
Other income increased primarily due to:
· | an increase in distributions of $25 million earned by Entergy Louisiana and $9 million earned by Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company. The distributions on preferred membership interests are eliminated in consolidation and have no effect on Entergy's net income because the investment is in another Entergy subsidiary. See Note 2 to the financial statements for a discussion of these investments in preferred membership interests; |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
· | carrying charges of $35 million on Hurricane Ike storm restoration costs as authorized by Texas legislation in the second quarter 2009; |
· | an increase of $15 million in allowance for equity funds used during construction due to more construction work in progress primarily as a result of Hurricane Gustav and Hurricane Ike; and |
· | a gain of $16 million recorded on the sale of undeveloped real estate by Entergy Louisiana Properties, LLC. |
These increases in other income were partially offset by a decreaseits balance sheet the funded status of $14 million in taxes collected on advances for transmission projects and a decrease of $18 million resulting from lower interest earned on the decommissioning trust funds and short-term investments.
Interest charges increased primarily dueits benefit plans. Refer to an increase in long-term debt outstanding resulting from debt issuances by certain of the Utility operating companies in the second half of 2008 and in 2009.
Non-Utility Nuclear
Other operation and maintenance expenses increased from $773 million in 2008 to $849 million in 2009 primarily due to $46 million in outside service costs and incremental labor costs related to the planned spin-off of the Non-Utility Nuclear business. Also contributing to the increase were higher nuclear labor and regulatory costs.
Other income increased primarily due to increases in interest income and realized earnings from the decommissioning trust funds and interest income from loans to Entergy subsidiaries. These increases were partially offset by $86 million in charges in 2009 compared to $50 million in charges in 2008 resulting from the recognition of impairments of certain equity securities held in Non-Utility Nuclear's decommissioning trust funds that are not considered temporary.
Parent & Other
Other operation and maintenance expenses decreased for the parent company, Entergy Corporation, primarily due to a decrease in outside services costs of $38 million related to the planned spin-off of the Non-Utility Nuclear business.
Other income decreased primarily due to:
· | an increase in the elimination for consolidation purposes of interest income from Entergy subsidiaries; and |
· | increases in the elimination for consolidation purposes of distributions earned of $25 million by Entergy Louisiana and $9 million by Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company, as discussed above. |
Interest charges decreased primarily due to lower interest rates on borrowings under Entergy Corporation's revolving credit facility.
Income Taxes
The effective income tax rate for 2009 was 33.6%. The reduction in the effective income tax rate versus the federal statutory rate of 35% in 2009 is primarily due to:
· | a tax benefit of approximately $28 million recognized on a capital loss resulting from the sale of preferred stock of Entergy Asset Management, Inc., a non-nuclear wholesale subsidiary, to a third party; |
· | the recognition of state loss carryovers in the amount of $24.3 million that had been subject to a valuation allowance; |
· | the recognition of a federal capital loss carryover of $16.2 million that had been subject to a valuation allowance; |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
· | settlements and agreements with taxing authorities resulting in a release $15.2 million of certain items from the provision for uncertain tax positions; |
· | an adjustment to state income taxes of $13.8 million for Non-Utility Nuclear to reflect the effect of a change in the methodology of computing Massachusetts state income taxes as required by that state's taxing authority; and |
· | an additional deferred tax benefit of approximately $8 million associated with writedowns on nuclear decommissioning qualified trust securities. |
These reductions were partially offset by increases related to book and tax differences for utility plant items and state income taxes at the Utility operating companies.
The effective income tax rate for 2008 was 32.7%. The reduction in the effective income tax rate versus the federal statutory rate of 35% in 2008 is primarily due to:
· | a capital loss recognized for income tax purposes on the liquidation of Entergy Power Generation, LLC in the third quarter 2008, which resulted in an income tax benefit of approximately $79.5 million. Entergy Power Generation, LLC was a holding company in Entergy's non-nuclear wholesale assets business; |
· | recognition of tax benefits of $44.3 million associated with the loss on sale of stock of Entergy Asset Management, Inc., a non-nuclear wholesale subsidiary, as a result of a settlement with the IRS; and |
· | an adjustment to state income taxes for Non-Utility Nuclear to reflect the effect of a change in the methodology of computing Massachusetts state income taxes resulting from legislation passed in the third quarter 2008, which resulted in an income tax benefit of approximately $18.8 million. |
These factors were partially offset by:
· | income taxes recorded by Entergy Power Generation, LLC, prior to its liquidation, resulting from the redemption payments it received in connection with its investment in Entergy Nuclear Power Marketing, LLC during the third quarter 2008, which resulted in an income tax expense of approximately $16.1 million; and |
· | book and tax differences for utility plant items and state income taxes at the Utility operating companies, including the flow-through treatment of the Entergy Arkansas write-offs discussed above. |
See Note 311 to the financial statements for a reconciliationfurther discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the federal statutorygreater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of 35.0% toreturn on assets by the effective income tax rates,market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and for additional discussion regarding income taxes.
expected returns. For other postretirement benefit plan assets Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysisuses fair value when determining MRV.
2008 Compared to 2007Costs and Funding
Following are income statement variancesIn 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for Utility, Non-Utility Nuclear, Parent & Other business segments, and Entergy comparing 2008 to 2007 showing how much the line item increased or (decreased) in comparison2012. Entergy’s contributions to the prior period:
| | | Utility | | Non-Utility Nuclear | | Parent & Other | | Entergy |
| | | (In Thousands) |
| | | | | | | | | |
| 2007 Consolidated Net Income (Loss) | | $704,393 | | $539,200 | | ($83,639) | | $1,159,954 |
| | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | | | | | | | | |
| Other operation and maintenance expenses | | 10,877 | | 13,289 | | 68,942 | | 93,108 |
| Taxes other than income taxes | | 1,544 | | 9,137 | | (2,787) | | 7,894 |
| Depreciation and amortization | | 38,898 | | 27,351 | | 899 | | 67,148 |
| Other income | | (2,871) | | (40,896) | | (42,001) | | (85,768) |
| Interest charges | | 2,834 | | 19,188 | | (50,153) | | (28,131) |
| Other | | 23,735 | | 38,558 | | 6 | | 62,299 |
| Income taxes | | (10,744) | | 88,700 | | 10,625 | | 88,581 |
| | | | | | | | | |
| 2008 Consolidated Net Income (Loss) | | $605,144 | | $797,280 | | ($161,889) | | $1,240,535 |
Referpension trust are currently estimated to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES" which accompanies Entergy Corporation's financial statements in this report for further information with respect to operating statistics.
Earnings were negatively affected in the fourth quarter 2007 by expenses of $52 million ($32 million net-of-tax) recorded in connection with a nuclear operations fleet alignment. This process was undertaken with the goals of eliminating redundancies, capturing economies of scale, and clearly establishing organizational governance. Most of the expenses related to the voluntary severance program offered to employees. Approximately 200 employees from the Non-Utility Nuclear business and 150 employees in the Utility business accepted the voluntary severance program offers.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2008 to 2007.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $4,618 |
Purchased power capacity | | (25) |
Volume/weather | | (14) |
Retail electric price | | 9 |
Other | | 1 |
2008 net revenue | | $4,589 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The purchased power capacity variance is primarily due to higher capacity charges. A portion of the variance is due to the amortization of deferred capacity costs and is offset in base revenues due to base rate increases implemented to recover incremental deferred and ongoing purchased power capacity charges.
The volume/weather variance is primarily due to the effect of less favorable weather compared to the same period in 2007 and decreased electricity usage primarily during the unbilled sales period. Hurricane Gustav and Hurricane Ike, which hit the Utility's service territories in September 2008, contributed an estimated $46 million to the decrease in electricity usage. Industrial sales were also depressed by the continuing effects of the hurricanes and, especially in the latter part of the year, because of the overall decline of the economy, leading to lower usage in the latter part of the year affecting both the large customer industrial segment as well as small and mid-sized industrial customers. The decreases in electricity usage were partially offset by an increase in residential and commercial customer electricity usage that occurred during the periods of the year not affected by the hurricanes.
The retail electric price variance is primarily due to:
· | an increase in the Attala power plant costs recovered through the power management rider by Entergy Mississippi. The net income effect of this recovery is limited to a portion representing an allowed return on equity with the remainder offset by Attala power plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes; |
· | a storm damage rider that became effective in October 2007 at Entergy Mississippi; and |
· | an Energy Efficiency rider that became effective in November 2007 at Entergy Arkansas. |
The establishment of the storm damage rider and the Energy Efficiency rider results in an increase in rider revenue and a corresponding increase in other operation and maintenance expense with no impact on net income. The retail electric price variance was partially offset by:
· | the absence of interim storm recoveries through the formula rate plans at Entergy Louisiana and Entergy Gulf States Louisiana which ceased upon the Act 55 financing of storm costs in the third quarter 2008; and |
· | a credit passed on to customers as a result of the Act 55 storm cost financings. |
Refer to "Liquidity and Capital Resources - Hurricane Katrina and Hurricane Rita" below and Note 2 to the financial statements for a discussion of the interim recovery of storm costs and the Act 55 storm cost financings.
Non-Utility Nuclear
Following is an analysis of the change in net revenue comparing 2008 to 2007.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $1,839 |
Realized price changes | | 309 |
Palisades acquisition | | 98 |
Volume variance (other than Palisades) | | 73 |
Fuel expenses (other than Palisades) | | (19) |
Other | | 34 |
2008 net revenue | | $2,334 |
As shown in the table above, net revenue for Non-Utility Nuclear increased by $495 million, or 27%, in 2008 compared to 2007 primarily due to higher pricing in its contracts to sell power, additional production available from the acquisition of Palisades in April 2007, and fewer outage days. In addition to the refueling outages shown in the table below, 2007
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
was affected by a 28 day unplanned outage. Included in the Palisades net revenue is $76 million and $50 million of amortization of the Palisades purchased power agreement in 2008 and 2007, respectively, which is non-cash revenue and is discussed in Note 15 to the financial statements. Following are key performance measures for 2008 and 2007:
| | | 2008 | | 2007 |
| | | | | |
| Net MW in operation at December 31 | | 4,998 | | 4,998 |
| Average realized price per MWh | | $59.51 | | $52.69 |
| GWh billed | | 41,710 | | 37,570 |
| Capacity factor | | 95% | | 89% |
| Refueling Outage Days: | | | | |
FitzPatrick | | 26 | | - |
Indian Point 2 | | 26 | | - |
Indian Point 3 | | - | | 24 |
Palisades | | - | | 42 |
Pilgrim | | - | | 33 |
Vermont Yankee | | 22 | | 24 |
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $1,856 million for 2007 to $1,867 million for 2008. The variance includes:
· | the write-off in the fourth quarter 2008 of $52 million of costs previously accumulated in Entergy Arkansas's storm reserve and $16 million of removal costs associated with the termination of a lease, both in connection with the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas's base rate case. The base rate case is discussed in more detail in Note 2 to the financial statements; |
· | a decrease of $39 million in payroll-related and benefits costs; |
· | a decrease of $21 million related to expenses recorded in 2007 in connection with the nuclear operations fleet alignment, as discussed above; |
· | a decrease of approximately $23 million as a result of the deferral or capitalization of storm restoration costs for Hurricane Gustav and Hurricane Ike, which hit the Utility's service territories in September 2008; |
· | an increase of $18 million in storm damage charges as a result of several storms hitting Entergy Arkansas' service territory in 2008, including Hurricane Gustav and Hurricane Ike in the third quarter 2008. Entergy Arkansas discontinued regulatory storm reserve accounting beginning July 2007 as a result of the APSC order issued in Entergy Arkansas' base rate case. As a result, non-capital storm expenses of $41 million were charged in 2008 to other operation and maintenance expenses. In December 2008, $19 million of these storm expenses were deferred per an APSC order and will be recovered through revenues in 2009. See Note 2 to the financial statements for discussion of the APSC order; and |
· | an increase of $17 million in fossil plant expenses due to the Ouachita plant acquisition in 2008. |
Depreciation and amortization expenses increased primarily due to:
· | a revision in the third quarter 2007 related to depreciation on storm cost-related assets. Recoveries of the costs of those assets are now through the Act 55 financing of storm costs, as approved by the LPSC in the third quarter 2007. See "Liquidity and Capital Resources - Hurricane Katrina and Hurricane Rita" below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
· | a revision in the fourth quarter 2008 of estimated depreciable lives involving certain intangible assets in accordance with formula rate plan treatment; and |
· | an increase in plant in service. |
Other income decreased primarily due to the cessation of carrying charges on storm restoration costs as a result of the Louisiana Act 55 storm cost financing approved in 2007 and lower interest earned on the decommissioning trust funds. This decrease was substantially offset by dividends earned of $29.5 million by Entergy Louisiana and $10.3 million by Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company. The dividends on preferred stock are eliminated in consolidation and have no effect on net income since the investment is in another Entergy subsidiary.
Non-Utility Nuclear
Other operation and maintenance expenses increased from $760be approximately $163.3 million in 2007 to $773 million in 2008. This increase was primarily due to deferring costs for amortization from three refueling outages in 2008 compared to four refueling outages in 2007 and to a $34 million increase associated with owning the Palisades plant, which was acquired in April 2007, for the entire period. The increase was partially offset by a decrease of $29 million related to expenses recorded in 2007 in connection with the nuclear operations fleet alignment, as discussed above.
Depreciation and amortization expenses increased from $99 million in 2007 to $126 million in 2008 as a result of the acquisition of Palisades in April 2007, which contributed $12 million to the increase, as well as other increases in plant in service.
Other income decreased primarily due to $50 million in charges to interest income in 2008 resulting from the recognition of impairments of certain equity securities held in Non-Utility Nuclear's decommissioning trust funds that are not considered temporary.
Other expenses increased due to increases of $23 million in nuclear refueling outage expenses and $15 million in decommissioning expenses that primarily resulted from the acquisition of Palisades in April 2007.
Parent & Other
Other operation and maintenance expenses increased for the parent company, Entergy Corporation, primarily due to outside services costs of $69 million related to the planned spin-off of the Non-Utility Nuclear business.
Other income decreased primarily due to the elimination for consolidation purposes of dividends earned of $29.5 million by Entergy Louisiana and $10.3 million by Entergy Gulf States Louisiana on investments in preferred membership interests of Entergy Holdings Company, as discussed above.
Interest charges decreased primarily due to lower interest rates on borrowings under Entergy Corporation's revolving credit facility.
Income Taxes
The effective income tax rate for 2008 was 32.7%. The reduction in the effective income tax rate versus the federal statutory rate of 35% in 2008 is primarily due to:
· | a capital loss recognized for income tax purposes on the liquidation of Entergy Power Generation, LLC in the third quarter 2008, which resulted in an income tax benefit of approximately $79.5 million. Entergy Power Generation, LLC was a holding company in Entergy's non-nuclear wholesale assets business; |
· | recognition of tax benefits of $44.3 million associated with the loss on sale of stock of Entergy Asset Management, Inc., a non-nuclear wholesale subsidiary, as a result of a settlement with the IRS; and |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
· | an adjustment to state income taxes for Non-Utility Nuclear to reflect the effect of a change in the methodology of computing Massachusetts state income taxes resulting from legislation passed in the third quarter 2008, which resulted in an income tax benefit of approximately $18.8 million. |
These factors were partially offset by:
· | income taxes recorded by Entergy Power Generation, LLC, prior to its liquidation, resulting from the redemption payments it received in connection with its investment in Entergy Nuclear Power Marketing, LLC during the third quarter 2008, which resulted in an income tax expense of approximately $16.1 million; and |
· | book and tax differences for utility plant items and state income taxes at the Utility operating companies, including the flow-through treatment of the Entergy Arkansas write-offs discussed above. |
The effective income tax rate for 2007 was 30.7%. The reduction in the effective income tax rate versus the federal statutory rate of 35% in 2007 is primarily due to:
· | a reduction in income tax expense due to a step-up in the tax basis on the Indian Point 2 non-qualified decommissioning trust fund resulting from restructuring of the trusts, which reduced deferred taxes on the trust fund and reduced current tax expense; |
· | the resolution of tax audit issues involving the 2002-2003 audit cycle; |
· | an adjustment to state income taxes for Non-Utility Nuclear to reflect the effect of a change in the methodology of computing New York state income taxes as required by that state's taxing authority; |
· | book and tax differences related to the allowance for equity funds used during construction; and |
· | the amortization of investment tax credits. |
These factors were partially offset by book and tax differences for utility plant items and state income taxes at the Utility operating companies.
See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates, and for additional discussion regarding income taxes.
Liquidity and Capital Resources
This section discusses Entergy's capital structure, capital spending plans and other uses of capital, sources of capital, and the cash flow activity presented in the cash flow statement.
Capital Structure
Entergy's capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital percentage from 2008 to 2009 is primarily the result of an increase in shareholders' equity primarily due to an increase in retained earnings, partially offset by repurchases of common stock, along with a decrease in borrowings under Entergy Corporation's revolving credit facility. The increase in the debt to capital percentage from 2007 to 2008 is primarily the result of additional borrowings under Entergy Corporation's revolving credit facility.
| | | 2009 | | 2008 | | 2007 |
| | | | | | | |
| Net debt to net capital at the end of the year | | 53.5% | | 55.6% | | 54.7% |
| Effect of subtracting cash from debt | | 3.8% | | 4.1% | | 2.9% |
| Debt to capital at the end of the year | | 57.3% | | 59.7% | | 57.6% |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, preferred stock with sinking fund, and long-term debt, including the currently maturing portion. Capital consists of debt, shareholders' equity, and preferred stock without sinking fund. Net capital consists of capital less cash and cash equivalents. Entergy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy's financial condition.
Long-term debt, including the currently maturing portion, makes up substantially all of Entergy's total debt outstanding. Following are Entergy's long-term debt principal maturities and estimated interest payments as of December 31, 2009. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2009. The figures below include payments on the Entergy Louisiana and System Energy sale-leaseback transactions, which are included in long-term debt on the balance sheet.
| Long-term debt maturities and estimated interest payments | | 2010 | | 2011 | | 2012 | | 2013-2014 | | after 2014 |
| | | (In Millions) |
| | | | | | | | | | | |
| Utility | | $863 | | $796 | | $596 | | $1,590 | | $9,865 |
| Non-Utility Nuclear | | 36 | | 33 | | 31 | | 41 | | 65 |
Parent Company and Other Business Segments | | 328 | | 122 | | 2,587 | | - | | - |
| Total | | $1,227 | | $951 | | $3,214 | | $1,631 | | $9,930 |
Note 5 to the financial statements provides more detail concerning long-term debt.
Entergy Corporation has a revolving credit facility that expires in August 2012 and has a borrowing capacity of $3.5 billion. Entergy Corporation also has the ability to issue letters of credit against the total borrowing capacity of the credit facility. The facility fee is currently 0.09% of the commitment amount. Facility fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 2009 was 1.377% on the drawn portion of the facility.
As of December 31, 2009, amounts outstanding and capacity available under the $3.5 billion credit facility are:
Capacity | | Borrowings | | Letters of Credit | | Capacity Available |
| (In Millions) |
| | | | | | | |
| $3,500 | | $2,566 | | $28 | | $906 |
Under covenants contained in Entergy Corporation's credit facility and in the indenture governing Entergy Corporation's senior notes, Entergy is required to maintain a consolidated debt ratio of 65% or less of its total capitalization. The calculation of this debt ratio under Entergy Corporation's credit facility and in the indenture governing the Entergy Corporation senior notes is different than the calculation of the debt to capital ratio above. Entergy is currently in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the Entergy Corporation credit facility's maturity date may occur and there may be an acceleration of amounts due under Entergy Corporation's senior notes.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Capital lease obligations, including nuclear fuel leases, are a minimal part of Entergy's overall capital structure, and are discussed in Note 10 to the financial statements. Following are Entergy's payment obligations under those leases:
| | 2010 | | 2011 | | 2012 | | 2013-2014 | | after 2014 | |
| | (In Millions) |
| Capital lease payments, including nuclear fuel leases | $212 | | $319 | | $3 | | $4 | | $28 | |
Notes payable includes borrowings outstanding on credit facilities with original maturities of less than one year. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas each had credit facilities available as of December 31, 2009 as follows:
Company
| | Expiration Date
| | Amount of
Facility
| | Interest Rate (a)
| | Amount Drawn as
of Dec. 31, 2009
|
| | | | | | | | |
Entergy Arkansas | | April 2010 | | $88 million (b) | | 5.00% | | - |
Entergy Gulf States Louisiana | | August 2012 | | $100 million (c) | | 0.71% | | - |
Entergy Louisiana | | August 2012 | | $200 million (d) | | 0.64% | | - |
Entergy Mississippi | | May 2010 | | $35 million (e) | | 1.98% | | - |
Entergy Mississippi | | May 2010 | | $25 million (e) | | 1.98% | | - |
Entergy Mississippi | | May 2010 | | $10 million (e) | | 1.91% | | - |
Entergy Texas | | August 2012 | | $100 million (f) | | 0.71% | | - |
(a) | The interest rate is the weighted average interest rate as of December 31, 2009 applied or that would be applied to the outstanding borrowings under the facility. |
(b) | The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization and contains an interest rate floor of 5%. Borrowings under the Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable. |
(c) | The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2009, no letters of credit were outstanding. The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement, the amount of debt assumed by Entergy Texas ($168 million as of December 31, 2009 and $770 million as of December 31, 2008) is excluded from debt and capitalization in calculating the debt ratio. |
(d) | The credit facility allows Entergy Louisiana to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2009, no letters of credit were outstanding. The credit agreement requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
(e) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable. Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
(f) | The credit facility allows Entergy Texas to issue letters of credit against the borrowing capacity of the facility. As of December 31, 2009, no letters of credit were outstanding. The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement, securitization bonds are excluded from debt and capitalization in calculating the debt ratio. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Operating Lease Obligations and Guarantees of Unconsolidated Obligations
Entergy has a minimal amount of operating lease obligations and guarantees in support of unconsolidated obligations. Entergy's guarantees in support of unconsolidated obligations are not likely to have a material effect on Entergy's financial condition or results of operations. Following are Entergy's payment obligations as of December 31, 2009 on non-cancelable operating leases with a term over one year:
| | 2010 | | 2011 | | 2012 | | 2013-2014 | | after 2014 | |
| | (In Millions) |
| | | | | | | | | | | |
| Operating lease payments | $95 | | $79 | | $66 | | $117 | | $173 | |
The operating leases are discussed in Note 10 to the financial statements.
Summary of Contractual Obligations of Consolidated Entities
| Contractual Obligations | | 2010 | | 2011-2012 | | 2013-2014 | | after 2014 | | Total |
| | | (In Millions) |
| | | | | | | | | | | |
| Long-term debt (1) | | $1,227 | | $4,165 | | $1,631 | | $9,930 | | $16,953 |
| Capital lease payments (2) | | $212 | | $322 | | $4 | | $28 | | $566 |
| Operating leases (2) | | $95 | | $145 | | $117 | | $173 | | $530 |
| Purchase obligations (3) | | $1,649 | | $2,793 | | $1,689 | | $5,692 | | $11,823 |
(1) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
(2) | Capital lease payments include nuclear fuel leases. Lease obligations are discussed in Note 10 to the financial statements. |
(3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. Almost all of the total are fuel and purchased power obligations. |
In addition to the contractual obligations, Entergy expects to make payments of approximately $61 million for the years 2010-2012 primarily related to Hurricane Katrina restoration work, including approximately $55 million of continued gas rebuild work at Entergy New Orleans. Also, Entergy currently expects to contribute approximately $270 million to its pension plans and approximately $76.4 million to other postretirement plans in 2010;2013, although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy's pension contributions in the future.2013.
Also in addition to the contractual obligations, Entergy has $328 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
· | maintain System Energy's equity capital at a minimum of 35% of its total capitalization (excluding short-term debt); |
· | permit the continued commercial operation of Grand Gulf; |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | payA 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in full all System Energy indebtednesscoverage limits for borrowed money when due;dependents; and |
| · | enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy's rights in the agreement as security for the specific debt.Elimination of lifetime caps. |
Capital Expenditure PlansThe effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and Other Usesregulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of CapitalPPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
Following areOne provision of the amountsnew law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Entergy's planned constructionMedicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other capital investments by operating segmentpostretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for 2010 through 2012:the Utility, including each Registrant Subsidiary, as a regulatory asset.
| Planned construction and capital investments | | 2010 | | 2011 | | 2012 |
| | | | (In Millions) |
| | | | | | | | |
| Maintenance Capital: | | | | | | |
| | Utility | | $776 | | $783 | | $822 |
| | Non-Utility Nuclear | | 92 | | 140 | | 123 |
| | Parent and Other | | 9 | | 7 | | 8 |
| | | | 877 | | 930 | | 953 |
| Capital Commitments: | | | | | | |
| | Utility | | 991 | | 1,578 | | 926 |
| | Non-Utility Nuclear | | 349 | | 220 | | 219 |
| | | | 1,340 | | 1,798 | | 1,145 |
| Total | | $2,217 | | $2,728 | | $2,098 |
Maintenance Capital refers to amounts Entergy plans to spend on routine capital projects that are necessary to support reliability of its service, equipment, or systems and to support normal customer growth.
Capital Commitments refers to non-routine capital investments for which Entergy is either contractually obligated, has Board approval, or otherwise expects to make to satisfy regulatory or legal requirements. Amounts reflected in this category include the following:
· | The currently planned construction or purchase of additional generation supply sources within the Utility's service territory through the Utility's portfolio transformation strategy, including Entergy Louisiana's planned purchase of Acadia Unit 2, which is discussed below. |
· | Entergy Louisiana's Waterford 3 steam generators replacement project, which is discussed below. |
· | System Energy's planned approximate 178 MW uprate of the Grand Gulf nuclear plant. The project is currently expected to cost $575 million, including transmission upgrades. On November 30, 2009, the MPSC issued a Certificate of Public Convenience and Necessity for implementation of the uprate. |
· | Transmission improvements and upgrades designed to provide greater transmission flexibility in the Entergy System. |
· | Initial development costs for potential new nuclear development at the Grand Gulf and River Bend sites, including licensing and design activities. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In addition, Entergy temporarily suspended reviews of the two license applications for the sites and will explore alternative nuclear technologies for this project. |
· | Spending to comply with current and anticipated North American Electric Reliability Corporation transmission planning requirements and NRC security requirements. |
· | Non-Utility Nuclear investments including dry cask spent fuel storage, nuclear license renewal efforts, component replacement across the fleet, NYPA value sharing, spending in response to the Indian Point Independent Safety Evaluation and spending to comply with revised NRC security requirements. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions.
| · | Environmental compliance spending, including approximately $420 million forChanges to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the 2010-2012 period for installationfiling of scrubbers and low NOx burners atother complaints in which Entergy Arkansas' White Bluff coal plant, which under current environmental regulations mustmay be operationalasserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by September 2013. Entergy Arkansas has requested a variance from that date, however, because the EPA has recently expressed concerns about Arkansas' Regional Haze State Implementation Plan and questioned the appropriateness of issuing an air permit prior to its approval of that plan. The White Bluff project is currently suspended, but the latest conceptual cost estimate indicates Entergy Arkansas' share of the project could cost approximately $465 million. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis.or relevant state or local authority. |
The Utility's generating capacity remains short of customer demand, and its supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. Estimated capital expenditures are also subject to periodic review and modification and may vary based on the ongoing effects of business restructuring, regulatory constraints and requirements, environmental regulations, business opportunities, market volatility, economic trends, and the ability to access capital.
Acadia Unit 2 Purchase Agreement
In October 2009, Entergy Louisiana announced that it has signed an agreement to acquire Unit 2 of the Acadia Energy Center, a 580 MW generating unit located near Eunice, La., from Acadia Power Partners, LLC, an independent power producer. The Acadia Energy Center, which entered commercial service in 2002, consists of two combined-cycle gas-fired generating units, each nominally rated at 580 MW. Entergy Louisiana proposes to acquire 100 percent of Acadia Unit 2 and a 50 percent ownership interest in the facility’s common assets for approximately $300 million. In a separate transaction entered into earlier this year, Cleco Power is acquiring Acadia Unit 1 and the other 50 percent interest in the facility’s common assets. Upon closing the transaction, Cleco Power will serve as operator for the entire facility. Entergy Louisiana has committed to sell one third of the output of Unit 2 to Entergy Gulf States Louisiana in accordance with terms and conditions detailed under the existing Entergy System Agreement.Litigation
Entergy Louisiana's purchase is contingent upon,regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies. Closing is expected to occurmatters. Entergy periodically reviews the cases in late 2010 or early 2011. Entergy Louisiana and Acadia Power Partners also have entered into a purchase power agreement for 100 percent of the output of Acadia Unit 2 that is expected to commence on May 1, 2010 and is set to expire at the closing of the acquisition transaction. Entergy Louisiana has filed with the LPSC for approval of the transaction, and no party filed an opposition to the purchase power agreement andwhich it has been forwarded tonamed as defendant and assesses the LPSClikelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for its review. The partiescases which have agreed to a procedural schedule forprobable likelihood of loss and can be estimated. Given the acquisition that would lead to LPSC considerationenvironment in which Entergy operates, and the unpredictable nature of many of the matter at its January 2011 meeting and includescases in which Entergy is named as a hearing beforedefendant, the ALJ in September 2010.ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Waterford 3 Steam Generator Replacement ProjectUncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy Louisiana plans to replaceevaluate risks such as the Waterford 3 steam generators, alongpotential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the reactor vessel closure head and control element drive mechanisms, in 2011. Replacement of these components is common to pressurized water reactors throughout the nuclear industry. The nuclear industry continues to address susceptibility to stress corrosion crackingtax treatment of certain materials associated withtransactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these components within the reactor coolant system. The issue is applicable to Waterford 3 and is managed in accordance with standard industry practices and guidelines. Routine inspections of the steam generators during Waterford 3's Fall 2006 refueling outage identified additional degradation of certain tube spacer supports in the steam generators that required repair beyond that anticipated prior to the outage. Corrective measures were successfully implemented to permit continued operation of the steam generators. While potentialprojects could have a material effect on Entergy’s future replacement of these components had been contemplated, additional steam generator tube and component degradation necessitates replacement of the steam generators as soon as reasonably achievable. The earliest the new steam generators can be manufactured and delivered for installation is 2011. A mid-cycle outage performed in 2007 supports Entergy Louisiana's 2011 replacement strategy. The reactor vessel head and control element drive mechanisms will be replaced at the same time, utilizing the same reactor building construction opening that is necessary for the steam generator replacement. net income, financial position, or cash flows.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In June 2008, Entergy Louisiana filed with the LPSC for approval of the project, including full cost recovery. Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding. The LPSC unanimously approved the settlement in November 2008. The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2) the decision to undertake the replacement project at the current estimated cost of $511 million is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extension or renewal of the formula rate plan or in a full base rate case including necessary pro forma adjustments. Upon completion of the replacement project, the LPSC will undertake a prudence review with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In July 2009, the LPSC granted Entergy Louisiana's motion to dismiss, without prejudice, its application seeking recovery of cash earnings on construction work in progress (CWIP) for the steam generator replacement project, acknowledging Entergy Louisiana's right, at any time, to seek cash earnings on CWIP if Entergy Louisiana believes that circumstances or projected circumstances are such that a request for cash earnings on CWIP is merited. The cash earnings on CWIP application had been consolidated with a similar request for the Little Gypsy repowering project, which was also dismissed in response to the same motion.ENTERGY CORPORATION AND SUBSIDIARIES
Entergy Louisiana estimates that it will spend approximately $511 million on this project, including $299 million over the 2010-2011 period.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant, and Entergy Gulf States Louisiana filed subsequently with the LPSC seeking certification to participate in one-third of the project. Petroleum coke and coal would be the unit's primary fuel sources. In July 2007, Entergy Louisiana filed with the LPSC for approval of the repowering project. In addition to seeking a finding that the project is in the public interest, the filing with the LPSC asked that Entergy Louisiana be allowed to recover a portion of the project's financing costs during the construction period.
On March 11, 2009, the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project's economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. On April 1, 2009, Entergy Louisiana complied with the LPSC's directive and recommended that the project be suspended for an extended period of time of three years or more. Entergy Louisiana estimated that its total costs for the project, if suspended, including actual spending to date and estimated contract cancellation costs, would be approximately $300 million. Entergy Louisiana had obtained all major environmental permits required to begin construction. A longer-term suspension places these permits at risk and may adversely affect the project's economics and technological feasibility. On May 22, 2009, the LPSC issued an order declaring that Entergy Louisiana's decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent. In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the project and seeking recovery over a five-year period of the project costs. The parties to the proceeding agreed to a procedural schedule that results in a hearing in October 2010. Entergy Louisiana currently estimates that its total costs for the project, if canceled, will be approximately $215 million, of which approximately $193 million was incurred through December 31, 2009.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Dividends and Stock Repurchases
Declarations of dividends on Entergy'sEntergy’s common stock are made at the discretion of the Board. Among other things, the Board evaluates the level of Entergy'sEntergy’s common stock dividends based upon Entergy'sEntergy’s earnings, financial strength, and future investment opportunities. At its January 20102013 meeting, the Board declared a dividend of $0.75$0.83 per share, which is the same quarterly dividend per share that Entergy has paid since thirdthe second quarter 2007.2010. The prior quarterly dividend per share was $0.75. Entergy paid $577$589 million in 2009, $5732012, $590 million in 2008,2011, and $507$604 million in 20072010 in cash dividends on its common stock.
In accordance with Entergy'sEntergy’s stock-based compensation plan,plans, Entergy periodically grants stock options, restricted stock, performance units, and restricted unit awards to its key employees, which may be exercised to obtain shares of Entergy'sEntergy’s common stock. According to the plan,plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy'sEntergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plan.plans.
In addition to the authority to fund grant exercises, in January 2007 the Board approved a program under which Entergy ishas authorized to repurchase up to $1.5 billion of its common stock. In January 2008, the Board authorized an incremental $500 million share repurchase programprograms to enable Entergy to consider opportunistic purchases in response to equity market conditions. Entergy completed both the $1.5 billion and $500 million programs in the third quarter 2009. In October 2009 the Board granted authority for an additionala $750 million share repurchase program which was completed in the fourth quarter 2010. In October 2010 the Board granted authority for an additional $500 million share repurchase program.
As of December 31, 2012, $350 million of authority remains under the $500 million share repurchase program. The amount of repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities, or if limitations in the credit markets continue for a prolonged period.
Sources of Capital
Entergy'sEntergy’s sources to meet its capital requirements and to fund potential investments include:
| · | internally generated funds; |
| · | cash on hand ($1.71 billion533 million as of December 31, 2009)2012); |
| · | bank financing under new or existing facilities;facilities or commercial paper; and |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Circumstances such as weather patterns, fuel and purchased power price fluctuations, and unanticipated expenses, including unscheduled plant outages and storms, could affect the timing and level of internally generated funds in the future.
Provisions within the Articles of Incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation'sCorporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock. As of December 31, 2009,2012, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $461.6$394.9 million and $236$68.5 million, respectively. All debt and common and preferred equity issuances by the Registrant Subsidiaries require prior regulatory approval and their preferred equity and debt issuances are also subject to issuance tests set forth in corporate charters, bond indentures, and other agreements. Entergy believes that the Registrant Subsidiaries have sufficient capacity under these tests to meet foreseeable capital needs.
The FERC has jurisdiction over securities issuances by the Utility operating companies and System Energy (except securities with maturities longer than one year issued by Entergy Arkansas and Entergy New Orleans, which are subject to the jurisdiction of the APSC and the City Council, respectively). No regulatory approvals are necessary for Entergy Corporation to issue securities. The current FERC-authorized short-term borrowing limits are effective through October 2011, as established by a FERC order issued October 14, 2009.31, 2013. Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizationauthorizations from the FERC andthat extend through July 2013. Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
has obtained long-term financing authorization from the APSC. The long-term securities issuances ofAPSC that extends through December 2015. Entergy New Orleans are limited to amounts authorized byhas obtained long-term financing authorization from the City Council and the current authorizationthat extends through August 2010.July 2014. In addition to borrowings from commercial banks, the FERC short-term borrowing orders authorizedauthorize the Registrant Subsidiaries to continue as participants in the Entergy System money pool. The money pool is an intercompany borrowing arrangement designed to reduce Entergy's subsidiaries'Entergy’s subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external short-term borrowings combined may not exceed authorizedthe FERC-authorized limits. As of December 31, 2009, Entergy's subsidiaries had no outstanding short-term borrowings from external sources. See Notes 4 and 5 to the financial statements for further discussion of Entergy'sEntergy’s borrowing limits, authorizations, and authorizations.amounts outstanding.
In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.
In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to portions of Entergy's service territories in Louisiana and Texas, and to a lesser extent in Arkansas and Mississippi. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). In July 2010 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. See Notes 2 and 3 to the financial statements for additional discussion of the Act 55 financings.
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas’s transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of storm cost recovery bonds, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. There is no recourse to Entergy or Entergy Arkansas in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the storm cost recovery bonds.
Entergy Louisiana Securitization Bonds – Little Gypsy
In August 2011 the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. There is no recourse to Entergy or Entergy Louisiana in the event of a bond default. See Note 5 to the financial statements for additional discussion of the issuance of the investment recovery bonds.
Cash Flow Activity
As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 694 | | | $ | 1,295 | | | $ | 1,710 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 2,940 | | | | 3,128 | | | | 3,926 | |
| Investing activities | | | (3,639 | ) | | | (3,447 | ) | | | (2,574 | ) |
| Financing activities | | | 538 | | | | (282 | ) | | | (1,767 | ) |
| Net decrease in cash and cash equivalents | | | (161 | ) | | | (601 | ) | | | (415 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 533 | | | $ | 694 | | | $ | 1,295 | |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Operating Activities
2012 Compared to 2011
Entergy's net cash provided by operating activities decreased by $188 million in 2012 compared to 2011 primarily due to:
| · | the decrease in Entergy Wholesale Commodities net revenue that is discussed previously; |
| · | Hurricane Isaac storm restoration spending in 2012; |
| · | income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; and |
| · | a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order. |
These decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
2011 Compared to 2010
Entergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane Gustav and Hurricane Ike. The Act 55 storm cost financings are discussed in Note 2 to the financial statements. The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.
Investing Activities
2012 Compared to 2011
Net cash used in investing activities increased by $192 million in 2012 compared to 2011 primarily due to an increase in construction expenditures, primarily in the Utility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012. Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital” above.
This increase was partially offset by:
| · | a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements; |
| · | proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and |
| · | a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2011 Compared to 2010
Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to:
| · | the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010. These transactions are described in more detail in Note 15 to the financial statements; |
| · | an increase in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and |
| · | a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas. The capital cost of repairing that damage was approximately $55 million. |
These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.
Financing Activities
2012 Compared to 2011
Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:
| · | long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility; |
| · | Entergy repurchasing $235 million of its common stock in 2011, as discussed below; |
| · | a net increase in 2012 of $51 million in short-term borrowings by the nuclear fuel company variable interest entities; and |
| · | $51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests. |
For the details of Entergy's commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. For the details of Entergy’s long-term debt outstanding, see Note 5 to the financial statements.
2011 Compared to 2010
Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010. The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million. For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements. In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010. Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Company | | Authorized Return on Common Equity |
| | |
Entergy Arkansas | | 10.2% |
| | |
| Entergy Gulf States Louisiana | | 9.9%-11.4% Electric; 10.0%-11.0% Gas |
| | |
Entergy Louisiana | | 9.45% - 11.05% |
| | |
| Entergy Mississippi | | 9.88% - 12.01% |
| | |
| Entergy New Orleans | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas |
| | |
Entergy Texas | | 9.8% |
The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Independent Coordinator of Transmission
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs. In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the ICT did not transfer control of the Entergy transmission system to the ICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
| · | granting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
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| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2008,2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
Entergy Corporation and Subsidiaries
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System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement Participation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
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Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. |
The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for 2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $163.3 million in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions.
| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority. |
Litigation
Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Uncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2012, which is included herein on pages 416 through 423.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2012. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation |
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc. |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
ALYSON M. MOUNT Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. | WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc. |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,302,079 | | | $ | 11,229,073 | | | $ | 11,487,577 | | | $ | 10,745,650 | | | $ | 13,093,756 | |
| Income from continuing operations | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | | | $ | 1,251,050 | | | $ | 1,240,535 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | | | $ | 6.39 | | | $ | 6.39 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | | | $ | 6.30 | | | $ | 6.20 | |
| Dividends declared per share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | | | $ | 3.00 | | | $ | 3.00 | |
| Return on common equity | | | 9.33 | % | | | 15.43 | % | | | 14.61 | % | | | 14.85 | % | | | 15.42 | % |
| Book value per share, year-end | | $ | 51.72 | | | $ | 50.81 | | | $ | 47.53 | | | $ | 45.54 | | | $ | 42.07 | |
| Total assets | | $ | 43,202,502 | | | $ | 40,701,699 | | | $ | 38,685,276 | | | $ | 37,561,953 | | | $ | 36,616,818 | |
| Long-term obligations (1) | | $ | 12,141,370 | | | $ | 10,268,645 | | | $ | 11,575,973 | | | $ | 11,277,314 | | | $ | 11,734,411 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 3,022 | | | $ | 3,369 | | | $ | 3,375 | | | $ | 2,999 | | | $ | 3,610 | |
| Commercial | | | 2,174 | | | | 2,333 | | | | 2,317 | | | | 2,184 | | | | 2,735 | |
| Industrial | | | 2,034 | | | | 2,307 | | | | 2,207 | | | | 1,997 | | | | 2,933 | |
| Governmental | | | 198 | | | | 205 | | | | 212 | | | | 204 | | | | 248 | |
| Total retail | | | 7,428 | | | | 8,214 | | | | 8,111 | | | | 7,384 | | | | 9,526 | |
| Sales for resale | | | 179 | | | | 216 | | | | 389 | | | | 206 | | | | 325 | |
| Other | | | 264 | | | | 244 | | | | 241 | | | | 290 | | | | 222 | |
| Total | | $ | 7,871 | | | $ | 8,674 | | | $ | 8,741 | | | $ | 7,880 | | | $ | 10,073 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 34,664 | | | | 36,684 | | | | 37,465 | | | | 33,626 | | | | 33,047 | |
| Commercial | | | 28,724 | | | | 28,720 | | | | 28,831 | | | | 27,476 | | | | 27,340 | |
| Industrial | | | 41,181 | | | | 40,810 | | | | 38,751 | | | | 35,638 | | | | 37,843 | |
| Governmental | | | 2,435 | | | | 2,474 | | | | 2,463 | | | | 2,408 | | | | 2,379 | |
| Total retail | | | 107,004 | | | | 108,688 | | | | 107,510 | | | | 99,148 | | | | 100,609 | |
| Sales for resale | | | 3,200 | | | | 4,111 | | | | 4,372 | | | | 4,862 | | | | 5,401 | |
| Total | | | 110,204 | | | | 112,799 | | | | 111,882 | | | | 104,010 | | | | 106,010 | |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,326 | | | $ | 2,414 | | | $ | 2,566 | | | $ | 2,711 | | | $ | 2,794 | |
| Billed Electric Energy Sales (GWh) | | | 46,178 | | | | 43,497 | | | | 42,934 | | | | 43,743 | | | | 44,875 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 27, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,870,649 | | | $ | 8,673,517 | | | $ | 8,740,637 | |
| Natural gas | | | 130,836 | | | | 165,819 | | | | 197,658 | |
| Competitive businesses | | | 2,300,594 | | | | 2,389,737 | | | | 2,549,282 | |
| TOTAL | | | 10,302,079 | | | | 11,229,073 | | | | 11,487,577 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,036,835 | | | | 2,492,714 | | | | 2,518,582 | |
| Purchased power | | | 1,255,800 | | | | 1,564,967 | | | | 1,659,416 | |
| Nuclear refueling outage expenses | | | 245,600 | | | | 255,618 | | | | 256,123 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Other operation and maintenance | | | 3,045,392 | | | | 2,867,758 | | | | 2,969,402 | |
| Decommissioning | | | 184,760 | | | | 190,595 | | | | 211,736 | |
| Taxes other than income taxes | | | 557,298 | | | | 536,026 | | | | 534,299 | |
| Depreciation and amortization | | | 1,144,585 | | | | 1,102,202 | | | | 1,069,894 | |
| Other regulatory charges - net | | | 175,104 | | | | 205,959 | | | | 44,921 | |
| TOTAL | | | 9,000,898 | | | | 9,215,839 | | | | 9,264,373 | |
| | | | | | | | | | | | | |
| Gain on sale of business | | | - | | | | - | | | | 44,173 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 1,301,181 | | | | 2,013,234 | | | | 2,267,377 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 92,759 | | | | 84,305 | | | | 59,381 | |
| Interest and investment income | | | 127,776 | | | | 128,994 | | | | 184,077 | |
| Miscellaneous - net | | | (53,214 | ) | | | (59,271 | ) | | | (48,124 | ) |
| TOTAL | | | 167,321 | | | | 154,028 | | | | 195,334 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 606,596 | | | | 551,521 | | | | 610,146 | |
| Allowance for borrowed funds used during construction | | | (37,312 | ) | | | (37,894 | ) | | | (34,979 | ) |
| TOTAL | | | 569,284 | | | | 513,627 | | | | 575,167 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 899,218 | | | | 1,653,635 | | | | 1,887,544 | |
| | | | | | | | | | | | | |
| Income taxes | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | |
| Dividends declared per common share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 177,324,813 | | | | 177,430,208 | | | | 186,010,452 | |
| Diluted average number of common shares outstanding | | | 177,737,565 | | | | 178,370,695 | | | | 187,814,235 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | | | | | | | |
| (net of tax expense (benefit) of ($55,750), $34,411, and ($7,088) | | | (97,591 | ) | | | 71,239 | | | | (11,685 | ) |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax benefit of $61,223, $131,198, and $14,387) | | | (91,157 | ) | | | (223,090 | ) | | | (8,527 | ) |
| Net unrealized investment gains | | | | | | | | | | | | |
| (net of tax expense of $61,104, $19,368, and $51,130) | | | 63,609 | | | | 21,254 | | | | 57,523 | |
| Foreign currency translation | | | | | | | | | | | | |
| (net of tax expense (benefit) of $275, $192, and ($182)) | | | 508 | | | | 357 | | | | (338 | ) |
| Other comprehensive income (loss) | | | (124,631 | ) | | | (130,240 | ) | | | 36,973 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | | 743,732 | | | | 1,237,132 | | | | 1,307,278 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| Comprehensive Income Attributable to Entergy Corporation | | $ | 722,042 | | | $ | 1,216,199 | | | $ | 1,287,215 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 1,771,649 | | | | 1,745,455 | | | | 1,705,331 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (26,479 | ) | | | (280,029 | ) | | | 718,987 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Gain on sale of business | | | - | | | | - | | | | (44,173 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (14,202 | ) | | | 28,091 | | | | (99,640 | ) |
| Fuel inventory | | | (11,604 | ) | | | 5,393 | | | | (10,665 | ) |
| Accounts payable | | | (6,779 | ) | | | (131,970 | ) | | | 216,635 | |
| Prepaid taxes and taxes accrued | | | 55,484 | | | | 580,042 | | | | (116,988 | ) |
| Interest accrued | | | 1,152 | | | | (34,172 | ) | | | 17,651 | |
| Deferred fuel costs | | | (99,987 | ) | | | (55,686 | ) | | | 8,909 | |
| Other working capital accounts | | | (151,989 | ) | | | 41,875 | | | | (160,326 | ) |
| Changes in provisions for estimated losses | | | (24,808 | ) | | | (11,086 | ) | | | 265,284 | |
| Changes in other regulatory assets | | | (398,428 | ) | | | (673,244 | ) | | | 339,408 | |
| Changes in pensions and other postretirement liabilities | | | 644,099 | | | | 962,461 | | | | (80,844 | ) |
| Other | | | (21,710 | ) | | | (415,685 | ) | | | (103,793 | ) |
| Net cash flow provided by operating activities | | | 2,940,285 | | | | 3,128,817 | | | | 3,926,081 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (2,674,650 | ) | | | (2,040,027 | ) | | | (1,974,286 | ) |
| Allowance for equity funds used during construction | | | 96,131 | | | | 86,252 | | | | 59,381 | |
| Nuclear fuel purchases | | | (557,960 | ) | | | (641,493 | ) | | | (407,711 | ) |
| Payment for purchase of plant | | | (456,356 | ) | | | (646,137 | ) | | | - | |
| Proceeds from sale of assets and businesses | | | - | | | | 6,531 | | | | 228,171 | |
| Insurance proceeds received for property damages | | | - | | | | - | | | | 7,894 | |
| Changes in securitization account | | | 4,265 | | | | (7,260 | ) | | | (29,945 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | (72,000 | ) |
| Payments to storm reserve escrow account | | | (8,957 | ) | | | (6,425 | ) | | | (296,614 | ) |
| Receipts from storm reserve escrow account | | | 27,884 | | | | - | | | | 9,925 | |
| Decrease (increase) in other investments | | | 15,175 | | | | (11,623 | ) | | | 24,956 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 109,105 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,074,055 | | | | 1,360,346 | | | | 2,606,383 | |
| Investment in nuclear decommissioning trust funds | | | (2,196,489 | ) | | | (1,475,017 | ) | | | (2,730,377 | ) |
| Net cash flow used in investing activities | | | (3,639,797 | ) | | | (3,446,853 | ) | | | (2,574,223 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | |
| Long-term debt | | | 3,478,361 | | | | 2,990,881 | | | | 3,870,694 | |
| Mandatorily redeemable preferred membership units of subsidiary | | | 51,000 | | | | - | | | | - | |
| Treasury stock | | | 62,886 | | | | 46,185 | | | | 51,163 | |
| Retirement of long-term debt | | | (3,130,233 | ) | | | (2,437,372 | ) | | | (4,178,127 | ) |
| Repurchase of common stock | | | - | | | | (234,632 | ) | | | (878,576 | ) |
| Redemption of subsidiary common and preferred stock | | | - | | | | (30,308 | ) | | | - | |
| Changes in credit borrowings and commercial paper - net | | | 687,675 | | | | (6,501 | ) | | | (8,512 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (589,209 | ) | | | (589,605 | ) | | | (603,854 | ) |
| Preferred stock | | | (22,329 | ) | | | (20,933 | ) | | | (20,063 | ) |
| Net cash flow provided by (used in) financing activities | | | 538,151 | | | | (282,285 | ) | | | (1,767,275 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (508 | ) | | | 287 | | | | 338 | |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (161,869 | ) | | | (600,034 | ) | | | (415,079 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 694,438 | | | | 1,294,472 | | | | 1,709,551 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 532,569 | | | $ | 694,438 | | | $ | 1,294,472 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 546,125 | | | $ | 532,271 | | | $ | 534,004 | |
| Income taxes | | $ | 49,214 | | | $ | (2,042 | ) | | $ | 32,144 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 112,992 | | | $ | 81,468 | |
| Temporary cash investments | | | 419,577 | | | | 612,970 | |
| Total cash and cash equivalents | | | 532,569 | | | | 694,438 | |
| Securitization recovery trust account | | | 46,040 | | | | 50,304 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 568,871 | | | | 568,558 | |
| Allowance for doubtful accounts | | | (31,956 | ) | | | (31,159 | ) |
| Other | | | 161,408 | | | | 166,186 | |
| Accrued unbilled revenues | | | 303,392 | | | | 298,283 | |
| Total accounts receivable | | | 1,001,715 | | | | 1,001,868 | |
| Deferred fuel costs | | | 150,363 | | | | 209,776 | |
| Accumulated deferred income taxes | | | 306,902 | | | | 9,856 | |
| Fuel inventory - at average cost | | | 213,831 | | | | 202,132 | |
| Materials and supplies - at average cost | | | 928,530 | | | | 894,756 | |
| Deferred nuclear refueling outage costs | | | 243,374 | | | | 231,031 | |
| System agreement cost equalization | | | 16,880 | | | | 36,800 | |
| Prepayments and other | | | 242,922 | | | | 291,742 | |
| TOTAL | | | 3,683,126 | | | | 3,622,703 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 46,738 | | | | 44,876 | |
| Decommissioning trust funds | | | 4,190,108 | | | | 3,788,031 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 256,039 | | | | 260,436 | |
| Other | | | 436,234 | | | | 416,423 | |
| TOTAL | | | 4,929,119 | | | | 4,509,766 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 41,944,567 | | | | 39,385,524 | |
| Property under capital lease | | | 935,199 | | | | 809,449 | |
| Natural gas | | | 353,492 | | | | 343,550 | |
| Construction work in progress | | | 1,365,699 | | | | 1,779,723 | |
| Nuclear fuel | | | 1,598,430 | | | | 1,546,167 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 46,197,387 | | | | 43,864,413 | |
| Less - accumulated depreciation and amortization | | | 18,898,842 | | | | 18,255,128 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 27,298,545 | | | | 25,609,285 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 742,030 | | | | 799,006 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $914,751 as of December 31, 2012 and $1,009,103 as of | | | | | | | | |
| December 31, 2011) | | | 5,025,912 | | | | 4,636,871 | |
| Deferred fuel costs | | | 172,202 | | | | 172,202 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Accumulated deferred income taxes | | | 37,748 | | | | 19,003 | |
| Other | | | 936,648 | | | | 955,691 | |
| TOTAL | | | 7,291,712 | | | | 6,959,945 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 718,516 | | | $ | 2,192,733 | |
| Notes payable and commercial paper | | | 796,002 | | | | 108,331 | |
| Accounts payable | | | 1,217,180 | | | | 1,069,096 | |
| Customer deposits | | | 359,078 | | | | 351,741 | |
| Taxes accrued | | | 333,719 | | | | 278,235 | |
| Accumulated deferred income taxes | | | 13,109 | | | | 99,929 | |
| Interest accrued | | | 184,664 | | | | 183,512 | |
| Deferred fuel costs | | | 96,439 | | | | 255,839 | |
| Obligations under capital leases | | | 3,880 | | | | 3,631 | |
| Pension and other postretirement liabilities | | | 95,900 | | | | 44,031 | |
| System agreement cost equalization | | | 25,848 | | | | 80,090 | |
| Other | | | 261,986 | | | | 283,531 | |
| TOTAL | | | 4,106,321 | | | | 4,950,699 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 8,311,756 | | | | 8,096,452 | |
| Accumulated deferred investment tax credits | | | 273,696 | | | | 284,747 | |
| Obligations under capital leases | | | 34,541 | | | | 38,421 | |
| Other regulatory liabilities | | | 898,614 | | | | 728,193 | |
| Decommissioning and asset retirement cost liabilities | | | 3,513,634 | | | | 3,296,570 | |
| Accumulated provisions | | | 362,226 | | | | 385,512 | |
| Pension and other postretirement liabilities | | | 3,725,886 | | | | 3,133,657 | |
| Long-term debt (includes securitization bonds of $973,480 as of | | | | | | | | |
| December 31, 2012 and $1,070,556 as of December 31, 2011) | | | 11,920,318 | | | | 10,043,713 | |
| Other | | | 577,910 | | | | 501,954 | |
| TOTAL | | | 29,618,581 | | | | 26,509,219 | |
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| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 186,511 | | | | 186,511 | |
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| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2012 and in 2011 | | | 2,548 | | | | 2,548 | |
| Paid-in capital | | | 5,357,852 | | | | 5,360,682 | |
| Retained earnings | | | 9,704,591 | | | | 9,446,960 | |
| Accumulated other comprehensive loss | | | (293,083 | ) | | | (168,452 | ) |
| Less - treasury stock, at cost (76,945,239 shares in 2012 and | | | | | | | | |
| 78,396,988 shares in 2011) | | | 5,574,819 | | | | 5,680,468 | |
| Total common shareholders' equity | | | 9,197,089 | | | | 8,961,270 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 9,291,089 | | | | 9,055,270 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 43,202,502 | | | $ | 40,701,699 | |
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| See Notes to Financial Statements. | | | | | | | | |
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| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
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| | | | | | Common Shareholders’ Equity | | | | |
| | | Subsidiaries’ Preferred Stock | | | Common Stock | | | Treasury Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 94,000 | | | $ | 2,548 | | | $ | (4,727,167 | ) | | $ | 5,370,042 | | | $ | 8,043,122 | | | $ | (75,185 | ) | | $ | 8,707,360 | |
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| Consolidated net income (a) | | | 20,063 | | | | - | | | | - | | | | - | | | | 1,250,242 | | | | - | | | | 1,270,305 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | 36,973 | | | | 36,973 | |
| Common stock repurchases | | | - | | | | - | | | | (878,576 | ) | | | - | | | | - | | | | - | | | | (878,576 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 80,932 | | | | (2,568 | ) | | | - | | | | - | | | | 78,364 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (603,963 | ) | | | - | | | | (603,963 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,063 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,063 | ) |
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| Balance at December 31, 2010 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,524,811 | ) | | $ | 5,367,474 | | | $ | 8,689,401 | | | $ | (38,212 | ) | | $ | 8,590,400 | |
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| Consolidated net income (a) | | | 20,933 | | | | - | | | | - | | | | - | | | | 1,346,439 | | | | - | | | | 1,367,372 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (130,240 | ) | | | (130,240 | ) |
| Common stock repurchases | | | - | | | | - | | | | (234,632 | ) | | | - | | | | - | | | | - | | | | (234,632 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 78,975 | | | | (6,792 | ) | | | - | | | | - | | | | 72,183 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (588,880 | ) | | | - | | | | (588,880 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,933 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,933 | ) |
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| Balance at December 31, 2011 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,680,468 | ) | | $ | 5,360,682 | | | $ | 9,446,960 | | | $ | (168,452 | ) | | $ | 9,055,270 | |
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| Consolidated net income (a) | | | 21,690 | | | | - | | | | - | | | | - | | | | 846,673 | | | | - | | | | 868,363 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (124,631 | ) | | | (124,631 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | $ | 105,649 | | | | (2,830 | ) | | | - | | | | - | | | | 102,819 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (589,042 | ) | | | - | | | | (589,042 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (21,690 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (21,690 | ) |
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| Balance at December 31, 2012 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,574,819 | ) | | $ | 5,357,852 | | | $ | 9,704,591 | | | $ | (293,083 | ) | | $ | 9,291,089 | |
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| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
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NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously-reported amounts have been reclassified to conform to current classifications, with no effect on net income or common shareholders’ (or members’) equity.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 9,588 | | | $ | 6,624 | | | $ | 2,964 | | | $ | - | |
Other | | | 2,878 | | | | 2,493 | | | | 385 | | | | - | |
| Transmission | | | 3,654 | | | | 3,619 | | | | 35 | | | | - | |
| Distribution | | | 6,561 | | | | 6,561 | | | | - | | | | - | |
| Other | | | 1,654 | | | | 1,416 | | | | 235 | | | | 3 | |
| Construction work in progress | | | 1,366 | | | | 973 | | | | 392 | | | | 1 | |
| Nuclear fuel | | | 1,598 | | | | 907 | | | | 691 | | | | - | |
| Property, plant, and equipment - net | | $ | 27,299 | | | $ | 22,593 | | | $ | 4,702 | | | $ | 4 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 8,635 | | | $ | 5,441 | | | $ | 3,194 | | | $ | - | |
Other | | | 2,431 | | | | 2,032 | | | | 399 | | | | - | |
| Transmission | | | 3,344 | | | | 3,309 | | | | 35 | | | | - | |
| Distribution | | | 6,157 | | | | 6,157 | | | | - | | | | - | |
| Other | | | 1,716 | | | | 1,463 | | | | 250 | | | | 3 | |
| Construction work in progress | | | 1,780 | | | | 1,420 | | | | 359 | | | | 1 | |
| Nuclear fuel | | | 1,546 | | | | 802 | | | | 744 | | | | - | |
| Property, plant, and equipment - net | | $ | 25,609 | | | $ | 20,624 | | | $ | 4,981 | | | $ | 4 | |
Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.
“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $230.4 million and $214.3 million as of December 31, 2012 and 2011, respectively.
Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2012 and 2011, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,073 | | | $ | 1,428 | | | $ | 2,180 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,943 | |
Other | | | 621 | | | | 286 | | | | 680 | | | | 545 | | | | (11 | ) | | | 371 | | | | - | |
| Transmission | | | 1,034 | | | | 573 | | | | 734 | | | | 581 | | | | 27 | | | | 642 | | | | 28 | |
| Distribution | | | 1,747 | | | | 939 | | | | 1,454 | | | | 1,065 | | | | 331 | | | | 1,025 | | | | - | |
| Other | | | 115 | | | | 187 | | | | 289 | | | | 201 | | | | 182 | | | | 106 | | | | 17 | |
| Construction work in progress | | | 206 | | | | 125 | | | | 405 | | | | 63 | | | | 11 | | | | 90 | | | | 40 | |
| Nuclear fuel | | | 304 | | | | 147 | | | | 204 | | | | - | | | | - | | | | - | | | | 253 | |
| Property, plant, and equipment - net | | $ | 5,100 | | | $ | 3,685 | | | $ | 5,946 | | | $ | 2,455 | | | $ | 540 | | | $ | 2,234 | | | $ | 2,281 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,034 | | | $ | 1,458 | | | $ | 1,561 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,388 | |
Other | | | 398 | | | | 286 | | | | 679 | | | | 350 | | | | (7 | ) | | | 325 | | | | - | |
| Transmission | | | 942 | | | | 500 | | | | 706 | | | | 510 | | | | 22 | | | | 624 | | | | 5 | |
| Distribution | | | 1,700 | | | | 856 | | | | 1,304 | | | | 1,009 | | | | 298 | | | | 990 | | | | - | |
| Other | | | 173 | | | | 192 | | | | 278 | | | | 206 | | | | 186 | | | | 110 | | | | 18 | |
| Construction work in progress | | | 120 | | | | 122 | | | | 559 | | | | 105 | | | | 14 | | | | 91 | | | | 358 | |
| Nuclear fuel | | | 273 | | | | 206 | | | | 165 | | | | - | | | | - | | | | - | | | | 158 | |
| Property, plant, and equipment - net | | $ | 4,640 | | | $ | 3,620 | | | $ | 5,252 | | | $ | 2,180 | | | $ | 513 | | | $ | 2,140 | | | $ | 1,927 | |
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2012 | | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
| 2011 | | 2.6% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.2% | | 2.8% |
| 2010 | | 2.9% | | 1.8% | | 2.4% | | 2.6% | | 3.1% | | 2.3% | | 2.9% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $142 million and $136 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.8 million and $2.7 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10 million and $9.8 million as of December 31, 2012 and 2011, respectively.
As of December 31, 2012, construction expenditures included in accounts payable are $56.3 million for Entergy Arkansas, $9.7 million for Entergy Gulf States Louisiana, $110.4 million for Entergy Louisiana, $4.8 million for Entergy Mississippi, $1.9 million for Entergy New Orleans, $8.6 million for Entergy Texas, and $13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2012, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $86 |
| | Common Facilities | | Coal | | | | 15.75% | | $33 | | $22 |
White Bluff | Units 1 and 2 | | Coal | | 1,659 | | 57.00% | | $498 | | $319 |
Ouachita (2) | Common Facilities | | Gas | | | | 66.67% | | $169 | | $142 |
Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 40.25% | | $250 | | $170 |
Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 15.92% | | $9 | | $3 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $142 | | $99 |
Ouachita (2) | Common Facilities | | Gas | | | | 33.33% | | $87 | | $73 |
| Entergy Louisiana - | | | | | | | | | | | |
| Acadia | Common Facilities | | Gas | | | | 50.00% | | $8 | | $- |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | 1,678 | | 25.00% | | $250 | | $140 |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 29.75% | | $180 | | $113 |
Roy S. Nelson | Unit 6 Common
Facilities | | Coal | | | | 11.77% | | $6 | | $2 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $107 | | $68 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,430(4) | | 90.00%(3) | | $4,557 | | $2,569 |
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Entergy Wholesale Commodities: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $69 | | $43 |
| Independence | Common
Facilities | | Coal | | | | 7.18% | | $16 | | $9 |
| Roy S. Nelson | Unit 6 | | Coal | | 540 | | 10.9% | | $104 | | $54 |
| Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 4.31% | | $2 | | $1 |
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| (1) | “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
| (3) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
| (4) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Earnings per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions, Except Per Share Data) | |
| | | | | | $/share | | | | | | $/share | | | | | | $/share | |
| Net income attributable to Entergy Corporation | | $ | 846.7 | | | | | | $ | 1,346.4 | | | | | | $ | 1,250.2 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Basic earnings per average common share | | | 177.3 | | | $ | 4.77 | | | | 177.4 | | | $ | 7.59 | | | | 186.0 | | | $ | 6.72 | |
| Average dilutive effect of: | | | | | | | | | | | | | | | | | | | | | | | | |
Stock options | | | 0.3 | | | | (0.01 | ) | | | 1.0 | | | | (0.04 | ) | | | 1.8 | | | | (0.06 | ) |
Other equity plans | | | 0.1 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Diluted earnings per average common shares | | | 177.7 | | | $ | 4.76 | | | | 178.4 | | | $ | 7.55 | | | | 187.8 | | | $ | 6.66 | |
The calculation of diluted earnings per share excluded 7,164,319 options outstanding at December 31, 2012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over three years.
Accounting for the Effects of Regulation
Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, where specific recovery is not provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the portion of River Bend that is not rate-regulated, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.
Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| · | Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act; |
| · | Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and |
| · | Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states. |
In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.
In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.
In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the VPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.
Impairment
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs | Range | Weighted
Average |
| | |
| Weighted average cost of capital | 7.5%-8.0% | 7.8% |
| Long-term pre-tax operating margin (cash basis) | 6.1%-7.8% | 7.2% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management (whose preferred holders also had protective rights until the securities were repurchased in December 2011), are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets
Other Regulatory Assets
Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2012 and 2011:
Entergy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 422.6 | | | $ | 395.9 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 35.1 | | | | 12.4 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Gas hedging costs - recovered through fuel rates | | | 8.3 | | | | 30.3 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 2,866.3 | | | | 2,542.0 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 970.8 | | | | 996.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 155.7 | | | | 81.2 | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 95.9 | | | | 108.8 | |
| Other | | | 75.1 | | | | 44.4 | |
Total | | $ | 5,025.9 | | | $ | 4,636.9 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 210.2 | | | $ | 187.7 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 831.2 | | | | 768.3 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.3 | | | | 4.6 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 115.2 | | | | 114.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 31.5 | | | | 34.7 | |
| Other | | | 6.2 | | | | 4.0 | |
Entergy Arkansas Total | | $ | 1,221.6 | | | $ | 1,126.9 | |
Entergy Gulf States Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 6.1 | | | $ | 12.8 | |
Gas hedging costs - recovered through fuel rates | | | 2.6 | | | | 8.6 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 300.5 | | | | 231.3 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 18.9 | | | | 10.2 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.9 | | | | 11.6 | |
| Other | | | 13.1 | | | | 4.1 | |
Entergy Gulf States Louisiana Total | | $ | 409.7 | | | $ | 333.9 | |
Entergy Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 136.9 | | | $ | 125.8 | |
Gas hedging costs - recovered through fuel rates | | | 3.4 | | | | 12.4 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 475.6 | | | | 427.9 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 74.5 | | | | 9.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 17.6 | | | | 20.0 | |
| Other | | | 28.0 | | | | 20.3 | |
Entergy Louisiana Total | | $ | 913.6 | | | $ | 814.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 5.6 | | | $ | 5.3 | |
Gas hedging costs - recovered through fuel rates | | | 2.2 | | | | 7.8 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 57.4 | | | | 48.5 | |
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.8 | | | | 7.8 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 234.6 | | | | 221.1 | |
Provision for storm damages - recovered through retail rates | | | 9.2 | | | | 30.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.6 | | | | 10.7 | |
| Other | | | 8.3 | | | | 4.7 | |
Entergy Mississippi Total | | $ | 401.5 | | | $ | 393.4 | |
Entergy New Orleans
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 3.6 | | | $ | 3.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 29.9 | | | | 16.3 | |
Gas hedging costs - recovered through fuel rates | | | - | | | | 1.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 134.6 | | | | 127.6 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 15.1 | | | | 8.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 2.3 | | | | 2.6 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
| Other | | | 5.5 | | | | 5.9 | |
Entergy New Orleans Total | | $ | 202.0 | | | $ | 178.8 | |
Entergy Texas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 1.2 | | | $ | 1.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 11.5 | | | | 4.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 258.8 | | | | 244.9 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 737.9 | | | | 822.5 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.4 | | | | 10.8 | |
| Other | | | 13.6 | | | | 4.9 | |
Entergy Texas Total | | $ | 1,114.5 | | | $ | 1,178.1 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 58.9 | | | $ | 59.6 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 56.8 | | | | 11.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b) | | | 198.2 | | | | 197.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 15.6 | | | | 18.2 | |
| Other | | | 0.6 | | | | 0.6 | |
System Energy Total | | $ | 330.1 | | | $ | 287.8 | |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
| (b) | Does not earn a return on investment, but is offset by related liabilities. |
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew a total of $229$10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Correction of Regulatory Asset for Income Taxes
In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and would not be recovered in the future.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a cumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.
The effect was also immaterial to the balance sheets, results of operations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Income Statement | | | | | | | | | | | | |
| Income taxes | | $ | 88,313 | | | $ | 89,736 | | | $ | 75,878 | | | $ | 92,297 | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Earnings applicable to common equity | | $ | 202,202 | | | $ | 200,779 | | | $ | 189,911 | | | $ | 173,492 | |
| | | | | | | | | | | | | | | | | |
| Statement of Cash Flows | | | | | | | | | | | | | | | | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | $ | (6,268 | ) | | $ | (4,845 | ) | | $ | 87,920 | | | $ | 104,339 | |
Changes in other regulatory assets | | $ | (80,027 | ) | | $ | (77,713 | ) | | $ | 114,528 | | | $ | 141,216 | |
Other operating activities | | $ | (35,248 | ) | | $ | (37,562 | ) | | $ | 30,717 | | | $ | 4,029 | |
| | | December 31, 2011 | |
| | | As previously reported | | | As corrected | |
| | | | | | | |
| Balance Sheet | | | | | | |
| Regulatory asset for income taxes - net | | $ | 249,058 | | | $ | 173,724 | |
Accumulated deferred income taxes - current | | $ | 5,427 | | | $ | 5,107 | |
Accumulated deferred income taxes and taxes accrued | | $ | 1,397,230 | | | $ | 1,368,563 | |
| Member’s equity | | $ | 1,439,733 | | | $ | 1,393,386 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Years Ended December 31, 2011 and 2010 | |
| | | Member’s Equity | | | Total Equity | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Statement of Changes in Equity | | | | | | |
| Balance at December 31, 2009 | | $ | 1,473,930 | | | $ | 1,445,425 | | | $ | 1,441,759 | | | $ | 1,413,254 | |
| 2010 Net income | | $ | 190,738 | | | $ | 174,319 | | | $ | 190,738 | | | $ | 174,319 | |
| Balance at December 31, 2010 | | $ | 1,539,517 | | | $ | 1,494,593 | | | $ | 1,509,213 | | | $ | 1,464,289 | |
| 2011 Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 203,027 | | | $ | 201,604 | |
| Balance at December 31, 2011 | | $ | 1,439,733 | | | $ | 1,393,386 | | | $ | 1,380,123 | | | $ | 1,333,776 | |
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2012 and 2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
| | | | | | | |
| Entergy Arkansas | | $ | 97.3 | | | $ | 209.8 | |
| Entergy Gulf States Louisiana (a) | | $ | 99.2 | | | $ | 2.9 | |
| Entergy Louisiana (a) | | $ | 94.6 | | | $ | 1.5 | |
| Entergy Mississippi | | $ | 26.5 | | | $ | (15.8 | ) |
| Entergy New Orleans (a) | | $ | 1.9 | | | $ | (7.5 | ) |
| Entergy Texas | | $ | (93.3 | ) | | $ | (64.7 | ) |
| (a) | 2012 and 2011 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana, and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2005 the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC’s January 2007 order in light of the arguments advanced in Entergy Arkansas’s rehearing petition and because the value for Entergy Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas’s rehearing request and the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. Testimony has been filed, and the APSC will decide the case based on the record in the proceeding, including the prefiled testimony.
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the attorney general’s suit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund was made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the PUCT a request to refund approximately $66 million, including interest, of fuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2009 Base Rate Filing
In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.
In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Interruptible Load Proceeding
In April 2007, the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.
In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.
Storm Cost Recovery Filings with Retail Regulators
Entergy Arkansas
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas's transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage
Entergy Corporation and Subsidiaries
Notes to Financial Statements
restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of approximately $126.3 million in storm cost recovery bonds, which includes carrying costs of $11.5 million and $4.6 million of up-front financing costs. See Note 5 to the financial statements for a discussion of the August 2010 issuance of the securitization bonds.
Entergy Arkansas December 2012 Winter Storm
In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas plans to present a cost recovery proposal to the APSC in a base rate case filing in March 2013.
Entergy Gulf States Louisiana and Entergy Louisiana
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy's service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana made a supplemental filing to, among other things, recommend recoveryand the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and replenishmentissuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings).Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm reservescosts were financed primarily by Louisiana Act 55 (passed in 2007) financing.financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana recovered their costs from Hurricane Katrinaalso filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Hurricane Rita primarily by Act 55 financing as discussed below. Onsavings to customers via a Storm Cost Offset rider.
In December 30, 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that if approved, provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana.Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financing isfinancings are accomplished. TheIn March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding have agreed to a procedural schedulefiled with the LPSC an uncontested stipulated settlement that includes March/April 2010 hearing dates for boththese terms and also includes Entergy Gulf States Louisiana’s and Entergy Louisiana's proposals under the recoverabilityAct 55 financings, which includes a commitment to pass on to customers a minimum of $15.5 million and the method of recovery proceedings.
Entergy Texas filed an application in April 2009 seeking a determination that $577.5$27.75 million of Hurricane Ikecustomer benefits, respectively, through prospective annual rate reductions of $3.1 million and Hurricane Gustav restoration costs are recoverable, including estimated costs$5.55 million for work to be completed. On August 5, 2009, Entergy Texas submitted tofive years. A stipulation hearing was held before the ALJ an unopposed settlement agreement intended to resolve all issues inon April 13, 2010. On April 21, 2010, the storm cost recovery case. Under the terms of the agreement $566.4 million, plus carrying costs, are eligible for recovery. Insurance proceeds will be credited as an offset to the securitized amount. Of the $11.1 million difference between Entergy Texas' request and the amount agreed to, which is part of the black box agreement and not directly attributable to any specific individual issues raised, $6.8 million is operation and maintenance expense for which Entergy Texas recorded a charge in the second quarter 2009. The remaining $4.3 million was recorded as utility plant. The PUCTLPSC approved the settlement in August 2009, and in September 2009subsequently issued two financing orders and one ratemaking order intended to facilitate the PUCT approved recoveryimplementation of the costs, plus carrying costs,Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4 million of bond proceeds loaned by securitization. In November 2009,the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Texas Restoration Funding,Louisiana and transferred $262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4 million to acquire 2,624,297.11 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy, Texas, issued $545.9 millionthat carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of senior secured transition bonds (securitization bonds). See Note 5 to$100 per unit. The preferred membership interests are callable at the financial statements for a discussionoption of Entergy Holdings Company LLC after ten years under the terms of the November 2009 issuanceLLC agreement. The terms of the securitization bonds.membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In July 2010, the third quarter 2009, Entergy settled with its insurer on its Hurricane Ike claim and Entergy Texas received $75.5LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds (Entergyloaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a totalcompany wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $76.5 million).
$100 per unit. The preferred membership interests are callable at the option of Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Arkansas January 2009 Ice StormHoldings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In January 2009Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a severe ice storm caused significant damagebond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy Arkansas' transmissionGulf States Louisiana and distribution lines, equipment, poles,Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and other facilities. On January 30, 2009, the APSC issued an order inviting and encouraging electric public utilities to file specific proposalscollection agents for the recovery of extraordinary storm restoration expenses associated with the ice storm. On February 16, 2009, Entergy Arkansas filed a request with the APSC for an accounting order authorizing deferral of the operating and maintenance cost portion of Entergy Arkansas' ice storm restoration costs pending their recovery. The APSC issued such an order in March 2009 subject to certain conditions, including that if Entergy Arkansas seeks to recover the deferred costs, those costs will be subject to investigation for whether they are incremental, prudent, and reasonable. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. On February 1, 2010, Entergy Arkansas requested a financing order to issue approximately $127.5 million in storm recovery bonds, which included carrying costs of $11.7 million and $4.6 million of up-front financing costs to pay for ice storm restoration because Entergy Arkansas' analysis demonstrates retail customers will benefit from lower costs using securitization. The APSC has established a procedural schedule that includes a hearing in April 2010 and states that the APSC will issue its final order by June 15, 2010. Entergy Arkansas' September 2009 general rate filing also requested recovery of the January 2009 ice storm costs over 10 years if it was expected that securitization would not produce lower costs for customers, and Entergy Arkansas will remove this request if the APSC approves securitization.state.
Cash Flow Activity
As shown in Entergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 694 | | | $ | 1,295 | | | $ | 1,710 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 2,940 | | | | 3,128 | | | | 3,926 | |
| Investing activities | | | (3,639 | ) | | | (3,447 | ) | | | (2,574 | ) |
| Financing activities | | | 538 | | | | (282 | ) | | | (1,767 | ) |
| Net decrease in cash and cash equivalents | | | (161 | ) | | | (601 | ) | | | (415 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 533 | | | $ | 694 | | | $ | 1,295 | |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Operating Activities
2012 Compared to 2011
Entergy's net cash provided by operating activities decreased by $188 million in 2012 compared to 2011 primarily due to:
| · | the decrease in Entergy Wholesale Commodities net revenue that is discussed previously; |
| · | Hurricane Isaac storm restoration spending in 2012; |
| · | income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; and |
| · | a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order. |
These decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
2011 Compared to 2010
Entergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in July 2010 of $703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings for Hurricane KatrinaGustav and Hurricane RitaIke. The Act 55 storm cost financings are discussed in Note 2 to the financial statements. The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.
Investing Activities
2012 Compared to 2011
Net cash used in investing activities increased by $192 million in 2012 compared to 2011 primarily due to an increase in construction expenditures, primarily in the Utility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012. Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital” above.
This increase was partially offset by:
| · | a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements; |
| · | proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and |
| · | a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2011 Compared to 2010
Net cash used in investing activities increased $873 million in 2011 compared to 2010 primarily due to:
| · | the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2010. These transactions are described in more detail in Note 15 to the financial statements; |
| · | an increase in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and |
| · | a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas. The capital cost of repairing that damage was approximately $55 million. |
These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.
Financing Activities
2012 Compared to 2011
Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:
| · | long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility; |
| · | Entergy repurchasing $235 million of its common stock in 2011, as discussed below; |
| · | a net increase in 2012 of $51 million in short-term borrowings by the nuclear fuel company variable interest entities; and |
| · | $51 million in proceeds from the sale to a third party in 2012 of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests. |
For the details of Entergy's commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. For the details of Entergy’s long-term debt outstanding, see Note 5 to the financial statements.
2011 Compared to 2010
Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010. The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million. For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements. In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010. Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies’ authorized returns on common equity:
Company | | Authorized Return on Common Equity |
| | |
Entergy Arkansas | | 10.2% |
| | |
| Entergy Gulf States Louisiana | | 9.9%-11.4% Electric; 10.0%-11.0% Gas |
| | |
Entergy Louisiana | | 9.45% - 11.05% |
| | |
| Entergy Mississippi | | 9.88% - 12.01% |
| | |
| Entergy New Orleans | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas |
| | |
Entergy Texas | | 9.8% |
The Utility operating companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Independent Coordinator of Transmission
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs. In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the ICT did not transfer control of the Entergy transmission system to the ICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
| · | granting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement Participation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. |
The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for 2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $163.3 million in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions.
| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority. |
Litigation
Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Uncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2012, which is included herein on pages 416 through 423.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2012. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation |
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc. |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
ALYSON M. MOUNT Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. | WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc. |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,302,079 | | | $ | 11,229,073 | | | $ | 11,487,577 | | | $ | 10,745,650 | | | $ | 13,093,756 | |
| Income from continuing operations | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | | | $ | 1,251,050 | | | $ | 1,240,535 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | | | $ | 6.39 | | | $ | 6.39 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | | | $ | 6.30 | | | $ | 6.20 | |
| Dividends declared per share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | | | $ | 3.00 | | | $ | 3.00 | |
| Return on common equity | | | 9.33 | % | | | 15.43 | % | | | 14.61 | % | | | 14.85 | % | | | 15.42 | % |
| Book value per share, year-end | | $ | 51.72 | | | $ | 50.81 | | | $ | 47.53 | | | $ | 45.54 | | | $ | 42.07 | |
| Total assets | | $ | 43,202,502 | | | $ | 40,701,699 | | | $ | 38,685,276 | | | $ | 37,561,953 | | | $ | 36,616,818 | |
| Long-term obligations (1) | | $ | 12,141,370 | | | $ | 10,268,645 | | | $ | 11,575,973 | | | $ | 11,277,314 | | | $ | 11,734,411 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 3,022 | | | $ | 3,369 | | | $ | 3,375 | | | $ | 2,999 | | | $ | 3,610 | |
| Commercial | | | 2,174 | | | | 2,333 | | | | 2,317 | | | | 2,184 | | | | 2,735 | |
| Industrial | | | 2,034 | | | | 2,307 | | | | 2,207 | | | | 1,997 | | | | 2,933 | |
| Governmental | | | 198 | | | | 205 | | | | 212 | | | | 204 | | | | 248 | |
| Total retail | | | 7,428 | | | | 8,214 | | | | 8,111 | | | | 7,384 | | | | 9,526 | |
| Sales for resale | | | 179 | | | | 216 | | | | 389 | | | | 206 | | | | 325 | |
| Other | | | 264 | | | | 244 | | | | 241 | | | | 290 | | | | 222 | |
| Total | | $ | 7,871 | | | $ | 8,674 | | | $ | 8,741 | | | $ | 7,880 | | | $ | 10,073 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 34,664 | | | | 36,684 | | | | 37,465 | | | | 33,626 | | | | 33,047 | |
| Commercial | | | 28,724 | | | | 28,720 | | | | 28,831 | | | | 27,476 | | | | 27,340 | |
| Industrial | | | 41,181 | | | | 40,810 | | | | 38,751 | | | | 35,638 | | | | 37,843 | |
| Governmental | | | 2,435 | | | | 2,474 | | | | 2,463 | | | | 2,408 | | | | 2,379 | |
| Total retail | | | 107,004 | | | | 108,688 | | | | 107,510 | | | | 99,148 | | | | 100,609 | |
| Sales for resale | | | 3,200 | | | | 4,111 | | | | 4,372 | | | | 4,862 | | | | 5,401 | |
| Total | | | 110,204 | | | | 112,799 | | | | 111,882 | | | | 104,010 | | | | 106,010 | |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,326 | | | $ | 2,414 | | | $ | 2,566 | | | $ | 2,711 | | | $ | 2,794 | |
| Billed Electric Energy Sales (GWh) | | | 46,178 | | | | 43,497 | | | | 42,934 | | | | 43,743 | | | | 44,875 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 27, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,870,649 | | | $ | 8,673,517 | | | $ | 8,740,637 | |
| Natural gas | | | 130,836 | | | | 165,819 | | | | 197,658 | |
| Competitive businesses | | | 2,300,594 | | | | 2,389,737 | | | | 2,549,282 | |
| TOTAL | | | 10,302,079 | | | | 11,229,073 | | | | 11,487,577 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,036,835 | | | | 2,492,714 | | | | 2,518,582 | |
| Purchased power | | | 1,255,800 | | | | 1,564,967 | | | | 1,659,416 | |
| Nuclear refueling outage expenses | | | 245,600 | | | | 255,618 | | | | 256,123 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Other operation and maintenance | | | 3,045,392 | | | | 2,867,758 | | | | 2,969,402 | |
| Decommissioning | | | 184,760 | | | | 190,595 | | | | 211,736 | |
| Taxes other than income taxes | | | 557,298 | | | | 536,026 | | | | 534,299 | |
| Depreciation and amortization | | | 1,144,585 | | | | 1,102,202 | | | | 1,069,894 | |
| Other regulatory charges - net | | | 175,104 | | | | 205,959 | | | | 44,921 | |
| TOTAL | | | 9,000,898 | | | | 9,215,839 | | | | 9,264,373 | |
| | | | | | | | | | | | | |
| Gain on sale of business | | | - | | | | - | | | | 44,173 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 1,301,181 | | | | 2,013,234 | | | | 2,267,377 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 92,759 | | | | 84,305 | | | | 59,381 | |
| Interest and investment income | | | 127,776 | | | | 128,994 | | | | 184,077 | |
| Miscellaneous - net | | | (53,214 | ) | | | (59,271 | ) | | | (48,124 | ) |
| TOTAL | | | 167,321 | | | | 154,028 | | | | 195,334 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 606,596 | | | | 551,521 | | | | 610,146 | |
| Allowance for borrowed funds used during construction | | | (37,312 | ) | | | (37,894 | ) | | | (34,979 | ) |
| TOTAL | | | 569,284 | | | | 513,627 | | | | 575,167 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 899,218 | | | | 1,653,635 | | | | 1,887,544 | |
| | | | | | | | | | | | | |
| Income taxes | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | |
| Dividends declared per common share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 177,324,813 | | | | 177,430,208 | | | | 186,010,452 | |
| Diluted average number of common shares outstanding | | | 177,737,565 | | | | 178,370,695 | | | | 187,814,235 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | | | | | | | |
| (net of tax expense (benefit) of ($55,750), $34,411, and ($7,088) | | | (97,591 | ) | | | 71,239 | | | | (11,685 | ) |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax benefit of $61,223, $131,198, and $14,387) | | | (91,157 | ) | | | (223,090 | ) | | | (8,527 | ) |
| Net unrealized investment gains | | | | | | | | | | | | |
| (net of tax expense of $61,104, $19,368, and $51,130) | | | 63,609 | | | | 21,254 | | | | 57,523 | |
| Foreign currency translation | | | | | | | | | | | | |
| (net of tax expense (benefit) of $275, $192, and ($182)) | | | 508 | | | | 357 | | | | (338 | ) |
| Other comprehensive income (loss) | | | (124,631 | ) | | | (130,240 | ) | | | 36,973 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | | 743,732 | | | | 1,237,132 | | | | 1,307,278 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| Comprehensive Income Attributable to Entergy Corporation | | $ | 722,042 | | | $ | 1,216,199 | | | $ | 1,287,215 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 1,771,649 | | | | 1,745,455 | | | | 1,705,331 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (26,479 | ) | | | (280,029 | ) | | | 718,987 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Gain on sale of business | | | - | | | | - | | | | (44,173 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (14,202 | ) | | | 28,091 | | | | (99,640 | ) |
| Fuel inventory | | | (11,604 | ) | | | 5,393 | | | | (10,665 | ) |
| Accounts payable | | | (6,779 | ) | | | (131,970 | ) | | | 216,635 | |
| Prepaid taxes and taxes accrued | | | 55,484 | | | | 580,042 | | | | (116,988 | ) |
| Interest accrued | | | 1,152 | | | | (34,172 | ) | | | 17,651 | |
| Deferred fuel costs | | | (99,987 | ) | | | (55,686 | ) | | | 8,909 | |
| Other working capital accounts | | | (151,989 | ) | | | 41,875 | | | | (160,326 | ) |
| Changes in provisions for estimated losses | | | (24,808 | ) | | | (11,086 | ) | | | 265,284 | |
| Changes in other regulatory assets | | | (398,428 | ) | | | (673,244 | ) | | | 339,408 | |
| Changes in pensions and other postretirement liabilities | | | 644,099 | | | | 962,461 | | | | (80,844 | ) |
| Other | | | (21,710 | ) | | | (415,685 | ) | | | (103,793 | ) |
| Net cash flow provided by operating activities | | | 2,940,285 | | | | 3,128,817 | | | | 3,926,081 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (2,674,650 | ) | | | (2,040,027 | ) | | | (1,974,286 | ) |
| Allowance for equity funds used during construction | | | 96,131 | | | | 86,252 | | | | 59,381 | |
| Nuclear fuel purchases | | | (557,960 | ) | | | (641,493 | ) | | | (407,711 | ) |
| Payment for purchase of plant | | | (456,356 | ) | | | (646,137 | ) | | | - | |
| Proceeds from sale of assets and businesses | | | - | | | | 6,531 | | | | 228,171 | |
| Insurance proceeds received for property damages | | | - | | | | - | | | | 7,894 | |
| Changes in securitization account | | | 4,265 | | | | (7,260 | ) | | | (29,945 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | (72,000 | ) |
| Payments to storm reserve escrow account | | | (8,957 | ) | | | (6,425 | ) | | | (296,614 | ) |
| Receipts from storm reserve escrow account | | | 27,884 | | | | - | | | | 9,925 | |
| Decrease (increase) in other investments | | | 15,175 | | | | (11,623 | ) | | | 24,956 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 109,105 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,074,055 | | | | 1,360,346 | | | | 2,606,383 | |
| Investment in nuclear decommissioning trust funds | | | (2,196,489 | ) | | | (1,475,017 | ) | | | (2,730,377 | ) |
| Net cash flow used in investing activities | | | (3,639,797 | ) | | | (3,446,853 | ) | | | (2,574,223 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | |
| Long-term debt | | | 3,478,361 | | | | 2,990,881 | | | | 3,870,694 | |
| Mandatorily redeemable preferred membership units of subsidiary | | | 51,000 | | | | - | | | | - | |
| Treasury stock | | | 62,886 | | | | 46,185 | | | | 51,163 | |
| Retirement of long-term debt | | | (3,130,233 | ) | | | (2,437,372 | ) | | | (4,178,127 | ) |
| Repurchase of common stock | | | - | | | | (234,632 | ) | | | (878,576 | ) |
| Redemption of subsidiary common and preferred stock | | | - | | | | (30,308 | ) | | | - | |
| Changes in credit borrowings and commercial paper - net | | | 687,675 | | | | (6,501 | ) | | | (8,512 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (589,209 | ) | | | (589,605 | ) | | | (603,854 | ) |
| Preferred stock | | | (22,329 | ) | | | (20,933 | ) | | | (20,063 | ) |
| Net cash flow provided by (used in) financing activities | | | 538,151 | | | | (282,285 | ) | | | (1,767,275 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (508 | ) | | | 287 | | | | 338 | |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (161,869 | ) | | | (600,034 | ) | | | (415,079 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 694,438 | | | | 1,294,472 | | | | 1,709,551 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 532,569 | | | $ | 694,438 | | | $ | 1,294,472 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 546,125 | | | $ | 532,271 | | | $ | 534,004 | |
| Income taxes | | $ | 49,214 | | | $ | (2,042 | ) | | $ | 32,144 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 112,992 | | | $ | 81,468 | |
| Temporary cash investments | | | 419,577 | | | | 612,970 | |
| Total cash and cash equivalents | | | 532,569 | | | | 694,438 | |
| Securitization recovery trust account | | | 46,040 | | | | 50,304 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 568,871 | | | | 568,558 | |
| Allowance for doubtful accounts | | | (31,956 | ) | | | (31,159 | ) |
| Other | | | 161,408 | | | | 166,186 | |
| Accrued unbilled revenues | | | 303,392 | | | | 298,283 | |
| Total accounts receivable | | | 1,001,715 | | | | 1,001,868 | |
| Deferred fuel costs | | | 150,363 | | | | 209,776 | |
| Accumulated deferred income taxes | | | 306,902 | | | | 9,856 | |
| Fuel inventory - at average cost | | | 213,831 | | | | 202,132 | |
| Materials and supplies - at average cost | | | 928,530 | | | | 894,756 | |
| Deferred nuclear refueling outage costs | | | 243,374 | | | | 231,031 | |
| System agreement cost equalization | | | 16,880 | | | | 36,800 | |
| Prepayments and other | | | 242,922 | | | | 291,742 | |
| TOTAL | | | 3,683,126 | | | | 3,622,703 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 46,738 | | | | 44,876 | |
| Decommissioning trust funds | | | 4,190,108 | | | | 3,788,031 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 256,039 | | | | 260,436 | |
| Other | | | 436,234 | | | | 416,423 | |
| TOTAL | | | 4,929,119 | | | | 4,509,766 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 41,944,567 | | | | 39,385,524 | |
| Property under capital lease | | | 935,199 | | | | 809,449 | |
| Natural gas | | | 353,492 | | | | 343,550 | |
| Construction work in progress | | | 1,365,699 | | | | 1,779,723 | |
| Nuclear fuel | | | 1,598,430 | | | | 1,546,167 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 46,197,387 | | | | 43,864,413 | |
| Less - accumulated depreciation and amortization | | | 18,898,842 | | | | 18,255,128 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 27,298,545 | | | | 25,609,285 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 742,030 | | | | 799,006 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $914,751 as of December 31, 2012 and $1,009,103 as of | | | | | | | | |
| December 31, 2011) | | | 5,025,912 | | | | 4,636,871 | |
| Deferred fuel costs | | | 172,202 | | | | 172,202 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Accumulated deferred income taxes | | | 37,748 | | | | 19,003 | |
| Other | | | 936,648 | | | | 955,691 | |
| TOTAL | | | 7,291,712 | | | | 6,959,945 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 718,516 | | | $ | 2,192,733 | |
| Notes payable and commercial paper | | | 796,002 | | | | 108,331 | |
| Accounts payable | | | 1,217,180 | | | | 1,069,096 | |
| Customer deposits | | | 359,078 | | | | 351,741 | |
| Taxes accrued | | | 333,719 | | | | 278,235 | |
| Accumulated deferred income taxes | | | 13,109 | | | | 99,929 | |
| Interest accrued | | | 184,664 | | | | 183,512 | |
| Deferred fuel costs | | | 96,439 | | | | 255,839 | |
| Obligations under capital leases | | | 3,880 | | | | 3,631 | |
| Pension and other postretirement liabilities | | | 95,900 | | | | 44,031 | |
| System agreement cost equalization | | | 25,848 | | | | 80,090 | |
| Other | | | 261,986 | | | | 283,531 | |
| TOTAL | | | 4,106,321 | | | | 4,950,699 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 8,311,756 | | | | 8,096,452 | |
| Accumulated deferred investment tax credits | | | 273,696 | | | | 284,747 | |
| Obligations under capital leases | | | 34,541 | | | | 38,421 | |
| Other regulatory liabilities | | | 898,614 | | | | 728,193 | |
| Decommissioning and asset retirement cost liabilities | | | 3,513,634 | | | | 3,296,570 | |
| Accumulated provisions | | | 362,226 | | | | 385,512 | |
| Pension and other postretirement liabilities | | | 3,725,886 | | | | 3,133,657 | |
| Long-term debt (includes securitization bonds of $973,480 as of | | | | | | | | |
| December 31, 2012 and $1,070,556 as of December 31, 2011) | | | 11,920,318 | | | | 10,043,713 | |
| Other | | | 577,910 | | | | 501,954 | |
| TOTAL | | | 29,618,581 | | | | 26,509,219 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 186,511 | | | | 186,511 | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2012 and in 2011 | | | 2,548 | | | | 2,548 | |
| Paid-in capital | | | 5,357,852 | | | | 5,360,682 | |
| Retained earnings | | | 9,704,591 | | | | 9,446,960 | |
| Accumulated other comprehensive loss | | | (293,083 | ) | | | (168,452 | ) |
| Less - treasury stock, at cost (76,945,239 shares in 2012 and | | | | | | | | |
| 78,396,988 shares in 2011) | | | 5,574,819 | | | | 5,680,468 | |
| Total common shareholders' equity | | | 9,197,089 | | | | 8,961,270 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 9,291,089 | | | | 9,055,270 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Common Shareholders’ Equity | | | | |
| | | Subsidiaries’ Preferred Stock | | | Common Stock | | | Treasury Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 94,000 | | | $ | 2,548 | | | $ | (4,727,167 | ) | | $ | 5,370,042 | | | $ | 8,043,122 | | | $ | (75,185 | ) | | $ | 8,707,360 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,063 | | | | - | | | | - | | | | - | | | | 1,250,242 | | | | - | | | | 1,270,305 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | 36,973 | | | | 36,973 | |
| Common stock repurchases | | | - | | | | - | | | | (878,576 | ) | | | - | | | | - | | | | - | | | | (878,576 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 80,932 | | | | (2,568 | ) | | | - | | | | - | | | | 78,364 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (603,963 | ) | | | - | | | | (603,963 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,063 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,063 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2010 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,524,811 | ) | | $ | 5,367,474 | | | $ | 8,689,401 | | | $ | (38,212 | ) | | $ | 8,590,400 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,933 | | | | - | | | | - | | | | - | | | | 1,346,439 | | | | - | | | | 1,367,372 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (130,240 | ) | | | (130,240 | ) |
| Common stock repurchases | | | - | | | | - | | | | (234,632 | ) | | | - | | | | - | | | | - | | | | (234,632 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 78,975 | | | | (6,792 | ) | | | - | | | | - | | | | 72,183 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (588,880 | ) | | | - | | | | (588,880 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,933 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,933 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2011 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,680,468 | ) | | $ | 5,360,682 | | | $ | 9,446,960 | | | $ | (168,452 | ) | | $ | 9,055,270 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 21,690 | | | | - | | | | - | | | | - | | | | 846,673 | | | | - | | | | 868,363 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (124,631 | ) | | | (124,631 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | $ | 105,649 | | | | (2,830 | ) | | | - | | | | - | | | | 102,819 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (589,042 | ) | | | - | | | | (589,042 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (21,690 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (21,690 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2012 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,574,819 | ) | | $ | 5,357,852 | | | $ | 9,704,591 | | | $ | (293,083 | ) | | $ | 9,291,089 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | �� | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously-reported amounts have been reclassified to conform to current classifications, with no effect on net income or common shareholders’ (or members’) equity.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 9,588 | | | $ | 6,624 | | | $ | 2,964 | | | $ | - | |
Other | | | 2,878 | | | | 2,493 | | | | 385 | | | | - | |
| Transmission | | | 3,654 | | | | 3,619 | | | | 35 | | | | - | |
| Distribution | | | 6,561 | | | | 6,561 | | | | - | | | | - | |
| Other | | | 1,654 | | | | 1,416 | | | | 235 | | | | 3 | |
| Construction work in progress | | | 1,366 | | | | 973 | | | | 392 | | | | 1 | |
| Nuclear fuel | | | 1,598 | | | | 907 | | | | 691 | | | | - | |
| Property, plant, and equipment - net | | $ | 27,299 | | | $ | 22,593 | | | $ | 4,702 | | | $ | 4 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 8,635 | | | $ | 5,441 | | | $ | 3,194 | | | $ | - | |
Other | | | 2,431 | | | | 2,032 | | | | 399 | | | | - | |
| Transmission | | | 3,344 | | | | 3,309 | | | | 35 | | | | - | |
| Distribution | | | 6,157 | | | | 6,157 | | | | - | | | | - | |
| Other | | | 1,716 | | | | 1,463 | | | | 250 | | | | 3 | |
| Construction work in progress | | | 1,780 | | | | 1,420 | | | | 359 | | | | 1 | |
| Nuclear fuel | | | 1,546 | | | | 802 | | | | 744 | | | | - | |
| Property, plant, and equipment - net | | $ | 25,609 | | | $ | 20,624 | | | $ | 4,981 | | | $ | 4 | |
Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.
“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $230.4 million and $214.3 million as of December 31, 2012 and 2011, respectively.
Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2012 and 2011, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,073 | | | $ | 1,428 | | | $ | 2,180 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,943 | |
Other | | | 621 | | | | 286 | | | | 680 | | | | 545 | | | | (11 | ) | | | 371 | | | | - | |
| Transmission | | | 1,034 | | | | 573 | | | | 734 | | | | 581 | | | | 27 | | | | 642 | | | | 28 | |
| Distribution | | | 1,747 | | | | 939 | | | | 1,454 | | | | 1,065 | | | | 331 | | | | 1,025 | | | | - | |
| Other | | | 115 | | | | 187 | | | | 289 | | | | 201 | | | | 182 | | | | 106 | | | | 17 | |
| Construction work in progress | | | 206 | | | | 125 | | | | 405 | | | | 63 | | | | 11 | | | | 90 | | | | 40 | |
| Nuclear fuel | | | 304 | | | | 147 | | | | 204 | | | | - | | | | - | | | | - | | | | 253 | |
| Property, plant, and equipment - net | | $ | 5,100 | | | $ | 3,685 | | | $ | 5,946 | | | $ | 2,455 | | | $ | 540 | | | $ | 2,234 | | | $ | 2,281 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,034 | | | $ | 1,458 | | | $ | 1,561 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,388 | |
Other | | | 398 | | | | 286 | | | | 679 | | | | 350 | | | | (7 | ) | | | 325 | | | | - | |
| Transmission | | | 942 | | | | 500 | | | | 706 | | | | 510 | | | | 22 | | | | 624 | | | | 5 | |
| Distribution | | | 1,700 | | | | 856 | | | | 1,304 | | | | 1,009 | | | | 298 | | | | 990 | | | | - | |
| Other | | | 173 | | | | 192 | | | | 278 | | | | 206 | | | | 186 | | | | 110 | | | | 18 | |
| Construction work in progress | | | 120 | | | | 122 | | | | 559 | | | | 105 | | | | 14 | | | | 91 | | | | 358 | |
| Nuclear fuel | | | 273 | | | | 206 | | | | 165 | | | | - | | | | - | | | | - | | | | 158 | |
| Property, plant, and equipment - net | | $ | 4,640 | | | $ | 3,620 | | | $ | 5,252 | | | $ | 2,180 | | | $ | 513 | | | $ | 2,140 | | | $ | 1,927 | |
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2012 | | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
| 2011 | | 2.6% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.2% | | 2.8% |
| 2010 | | 2.9% | | 1.8% | | 2.4% | | 2.6% | | 3.1% | | 2.3% | | 2.9% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $142 million and $136 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.8 million and $2.7 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10 million and $9.8 million as of December 31, 2012 and 2011, respectively.
As of December 31, 2012, construction expenditures included in accounts payable are $56.3 million for Entergy Arkansas, $9.7 million for Entergy Gulf States Louisiana, $110.4 million for Entergy Louisiana, $4.8 million for Entergy Mississippi, $1.9 million for Entergy New Orleans, $8.6 million for Entergy Texas, and $13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2012, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $86 |
| | Common Facilities | | Coal | | | | 15.75% | | $33 | | $22 |
White Bluff | Units 1 and 2 | | Coal | | 1,659 | | 57.00% | | $498 | | $319 |
Ouachita (2) | Common Facilities | | Gas | | | | 66.67% | | $169 | | $142 |
Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 40.25% | | $250 | | $170 |
Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 15.92% | | $9 | | $3 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $142 | | $99 |
Ouachita (2) | Common Facilities | | Gas | | | | 33.33% | | $87 | | $73 |
| Entergy Louisiana - | | | | | | | | | | | |
| Acadia | Common Facilities | | Gas | | | | 50.00% | | $8 | | $- |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | 1,678 | | 25.00% | | $250 | | $140 |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 29.75% | | $180 | | $113 |
Roy S. Nelson | Unit 6 Common
Facilities | | Coal | | | | 11.77% | | $6 | | $2 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $107 | | $68 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,430(4) | | 90.00%(3) | | $4,557 | | $2,569 |
| | | | | | | | | | | | |
Entergy Wholesale Commodities: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $69 | | $43 |
| Independence | Common
Facilities | | Coal | | | | 7.18% | | $16 | | $9 |
| Roy S. Nelson | Unit 6 | | Coal | | 540 | | 10.9% | | $104 | | $54 |
| Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 4.31% | | $2 | | $1 |
| | | | | | | | | | | | |
| (1) | “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
| (3) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
| (4) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Earnings per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions, Except Per Share Data) | |
| | | | | | $/share | | | | | | $/share | | | | | | $/share | |
| Net income attributable to Entergy Corporation | | $ | 846.7 | | | | | | $ | 1,346.4 | | | | | | $ | 1,250.2 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Basic earnings per average common share | | | 177.3 | | | $ | 4.77 | | | | 177.4 | | | $ | 7.59 | | | | 186.0 | | | $ | 6.72 | |
| Average dilutive effect of: | | | | | | | | | | | | | | | | | | | | | | | | |
Stock options | | | 0.3 | | | | (0.01 | ) | | | 1.0 | | | | (0.04 | ) | | | 1.8 | | | | (0.06 | ) |
Other equity plans | | | 0.1 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Diluted earnings per average common shares | | | 177.7 | | | $ | 4.76 | | | | 178.4 | | | $ | 7.55 | | | | 187.8 | | | $ | 6.66 | |
The calculation of diluted earnings per share excluded 7,164,319 options outstanding at December 31, 2012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over three years.
Accounting for the Effects of Regulation
Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, where specific recovery is not provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the portion of River Bend that is not rate-regulated, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.
Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| · | Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act; |
| · | Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and |
| · | Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states. |
In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.
In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.
In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the VPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.
Impairment
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs | Range | Weighted
Average |
| | |
| Weighted average cost of capital | 7.5%-8.0% | 7.8% |
| Long-term pre-tax operating margin (cash basis) | 6.1%-7.8% | 7.2% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management (whose preferred holders also had protective rights until the securities were repurchased in December 2011), are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets
Other Regulatory Assets
Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2012 and 2011:
Entergy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 422.6 | | | $ | 395.9 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 35.1 | | | | 12.4 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Gas hedging costs - recovered through fuel rates | | | 8.3 | | | | 30.3 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 2,866.3 | | | | 2,542.0 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 970.8 | | | | 996.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 155.7 | | | | 81.2 | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 95.9 | | | | 108.8 | |
| Other | | | 75.1 | | | | 44.4 | |
Total | | $ | 5,025.9 | | | $ | 4,636.9 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 210.2 | | | $ | 187.7 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 831.2 | | | | 768.3 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.3 | | | | 4.6 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 115.2 | | | | 114.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 31.5 | | | | 34.7 | |
| Other | | | 6.2 | | | | 4.0 | |
Entergy Arkansas Total | | $ | 1,221.6 | | | $ | 1,126.9 | |
Entergy Gulf States Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 6.1 | | | $ | 12.8 | |
Gas hedging costs - recovered through fuel rates | | | 2.6 | | | | 8.6 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 300.5 | | | | 231.3 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 18.9 | | | | 10.2 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.9 | | | | 11.6 | |
| Other | | | 13.1 | | | | 4.1 | |
Entergy Gulf States Louisiana Total | | $ | 409.7 | | | $ | 333.9 | |
Entergy Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 136.9 | | | $ | 125.8 | |
Gas hedging costs - recovered through fuel rates | | | 3.4 | | | | 12.4 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 475.6 | | | | 427.9 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 74.5 | | | | 9.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 17.6 | | | | 20.0 | |
| Other | | | 28.0 | | | | 20.3 | |
Entergy Louisiana Total | | $ | 913.6 | | | $ | 814.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 5.6 | | | $ | 5.3 | |
Gas hedging costs - recovered through fuel rates | | | 2.2 | | | | 7.8 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 57.4 | | | | 48.5 | |
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.8 | | | | 7.8 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 234.6 | | | | 221.1 | |
Provision for storm damages - recovered through retail rates | | | 9.2 | | | | 30.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.6 | | | | 10.7 | |
| Other | | | 8.3 | | | | 4.7 | |
Entergy Mississippi Total | | $ | 401.5 | | | $ | 393.4 | |
Entergy New Orleans
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 3.6 | | | $ | 3.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 29.9 | | | | 16.3 | |
Gas hedging costs - recovered through fuel rates | | | - | | | | 1.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 134.6 | | | | 127.6 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 15.1 | | | | 8.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 2.3 | | | | 2.6 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
| Other | | | 5.5 | | | | 5.9 | |
Entergy New Orleans Total | | $ | 202.0 | | | $ | 178.8 | |
Entergy Texas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 1.2 | | | $ | 1.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 11.5 | | | | 4.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 258.8 | | | | 244.9 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 737.9 | | | | 822.5 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.4 | | | | 10.8 | |
| Other | | | 13.6 | | | | 4.9 | |
Entergy Texas Total | | $ | 1,114.5 | | | $ | 1,178.1 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 58.9 | | | $ | 59.6 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 56.8 | | | | 11.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b) | | | 198.2 | | | | 197.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 15.6 | | | | 18.2 | |
| Other | | | 0.6 | | | | 0.6 | |
System Energy Total | | $ | 330.1 | | | $ | 287.8 | |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
| (b) | Does not earn a return on investment, but is offset by related liabilities. |
Hurricane Isaac
In August and September 2005, Hurricanes Katrina and Rita2012, Hurricane Isaac caused catastrophicextensive damage to large portions of the Utility'sEntergy's service territoriesarea in Louisiana, and to a lesser extent in Mississippi and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area.Arkansas. The storms and floodingstorm resulted in widespread power outages, significant damage primarily to electric distribution transmission, and generation and gas infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the estimated costs incurred that were necessary to return customers due to mandatory evacuationsservice. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Correction of Regulatory Asset for Income Taxes
In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the destructionfinancial accounting treatment of homesthose taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and businesses. would not be recovered in the future.
Entergy pursuedCorporation and Subsidiaries
Notes to Financial Statements
The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a broad rangecumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.
The effect was also immaterial to the balance sheets, results of initiativesoperations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Income Statement | | | | | | | | | | | | |
| Income taxes | | $ | 88,313 | | | $ | 89,736 | | | $ | 75,878 | | | $ | 92,297 | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Earnings applicable to common equity | | $ | 202,202 | | | $ | 200,779 | | | $ | 189,911 | | | $ | 173,492 | |
| | | | | | | | | | | | | | | | | |
| Statement of Cash Flows | | | | | | | | | | | | | | | | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | $ | (6,268 | ) | | $ | (4,845 | ) | | $ | 87,920 | | | $ | 104,339 | |
Changes in other regulatory assets | | $ | (80,027 | ) | | $ | (77,713 | ) | | $ | 114,528 | | | $ | 141,216 | |
Other operating activities | | $ | (35,248 | ) | | $ | (37,562 | ) | | $ | 30,717 | | | $ | 4,029 | |
| | | December 31, 2011 | |
| | | As previously reported | | | As corrected | |
| | | | | | | |
| Balance Sheet | | | | | | |
| Regulatory asset for income taxes - net | | $ | 249,058 | | | $ | 173,724 | |
Accumulated deferred income taxes - current | | $ | 5,427 | | | $ | 5,107 | |
Accumulated deferred income taxes and taxes accrued | | $ | 1,397,230 | | | $ | 1,368,563 | |
| Member’s equity | | $ | 1,439,733 | | | $ | 1,393,386 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Years Ended December 31, 2011 and 2010 | |
| | | Member’s Equity | | | Total Equity | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Statement of Changes in Equity | | | | | | |
| Balance at December 31, 2009 | | $ | 1,473,930 | | | $ | 1,445,425 | | | $ | 1,441,759 | | | $ | 1,413,254 | |
| 2010 Net income | | $ | 190,738 | | | $ | 174,319 | | | $ | 190,738 | | | $ | 174,319 | |
| Balance at December 31, 2010 | | $ | 1,539,517 | | | $ | 1,494,593 | | | $ | 1,509,213 | | | $ | 1,464,289 | |
| 2011 Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 203,027 | | | $ | 201,604 | |
| Balance at December 31, 2011 | | $ | 1,439,733 | | | $ | 1,393,386 | | | $ | 1,380,123 | | | $ | 1,333,776 | |
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover storm restorationfuel and business continuitypurchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2012 and 2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
| | | | | | | |
| Entergy Arkansas | | $ | 97.3 | | | $ | 209.8 | |
| Entergy Gulf States Louisiana (a) | | $ | 99.2 | | | $ | 2.9 | |
| Entergy Louisiana (a) | | $ | 94.6 | | | $ | 1.5 | |
| Entergy Mississippi | | $ | 26.5 | | | $ | (15.8 | ) |
| Entergy New Orleans (a) | | $ | 1.9 | | | $ | (7.5 | ) |
| Entergy Texas | | $ | (93.3 | ) | | $ | (64.7 | ) |
| (a) | 2012 and 2011 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana, and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2005 the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC’s January 2007 order in light of the arguments advanced in Entergy Arkansas’s rehearing petition and because the value for Entergy Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas’s rehearing request and the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. Testimony has been filed, and the APSC will decide the case based on the record in the proceeding, including the prefiled testimony.
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the attorney general’s suit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including obtaining reimbursementinterest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund was made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the PUCT a request to refund approximately $66 million, including interest, of fuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2009 Base Rate Filing
In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs coveredassociated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by insurance$4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing recovery through existinglitigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or new rate mechanisms regulatedlower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.
In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and localaccepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory bodies,asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Interruptible Load Proceeding
In April 2007, the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.
In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.
Storm Cost Recovery Filings with Retail Regulators
Entergy Arkansas
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas's transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage
Entergy Corporation and Subsidiaries
Notes to Financial Statements
restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of approximately $126.3 million in storm cost recovery bonds, which includes carrying costs of $11.5 million and $4.6 million of up-front financing costs. See Note 5 to the financial statements for a discussion of the August 2010 issuance of the securitization bonds.
Insurance ClaimsEntergy Arkansas December 2012 Winter Storm
In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has receivednot gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas plans to present a total of $317 million as of December 31, 2009 on its cost recovery proposal to the APSC in a base rate case filing in March 2013.
Entergy Gulf States Louisiana and Entergy Louisiana
Hurricane KatrinaGustav and Hurricane Rita insurance claims, including the settlements of its Hurricane Katrina claims with each of its two excess insurers. Entergy has substantially completed its insurance recoveries related to Hurricane Katrina and Hurricane Rita.
Storm Cost Financings
LouisianaIke
In MarchSeptember 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy's service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed atwith the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States LouisianaLouisiana’s and Entergy LouisianaLouisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana LegislatureRegular Session of 2007 (Act 55 financings). TheEntergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings are expected to produce additional customer benefits, as compared to Act 64 traditional securitization.discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider. On April 3, 2008, the Louisiana State Bond Commission granted preliminary approval for the Act 55 financings. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
financings. On April 10, 2008,In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana andentered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States LouisianaLouisiana’s and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10$15.5 million and $30$27.75 million of customer benefits, respectively, through prospective annual rate reductions of $2$3.1 million and $6$5.55 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 16, 2008,21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In May 2008,June 2010 the Louisiana State Bond Commission granted final approval ofapproved the Act 55 financings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
OnIn July 29, 2008,2010, the LPFALouisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $687.7$468.9 million in bonds under the aforementioned Act 55. From the $679$462.4 million of bond proceeds loaned by the LPFALCDA to the LURC, the LURC deposited $152$200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527$262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545used $262.4 million including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85to acquire 2,624,297.11 Class AB preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10%9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 20082010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
On August 26, 2008,In July 2010, the LPFALCDA issued $278.4another $244.1 million in bonds under the aforementioned Act 55. From the $274.7$240.3 million of bond proceeds loaned by the LPFALCDA to the LURC, the LURC deposited $87$90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7$150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana invested $189.4used $150.3 million including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39to acquire 1,502,643.04 Class AB preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10%9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 20082010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
Texas
In July 2006, Entergy, Texas filed an application with the PUCT with respect to its Hurricane Rita reconstruction costs incurred through March 2006. The filing asked the PUCT to determine the amount of reasonable and necessary hurricane reconstruction costs eligible for securitization and recovery, approve the recovery of carrying costs, and approve the manner in which Entergy Texas allocates those costs among its retail customer classes. In December 2006, the PUCT approved $381 million of reasonable and necessary hurricane reconstruction costs incurred through March 31, 2006, plus carrying costs, as eligible for recovery. After netting expected insurance proceeds, the amount is $353 million.
In April 2007, the PUCT issued its financing order authorizing the issuance of securitization bonds to recover the $353 million of hurricane reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. See Note 5 to the financial statements for a discussion of the June 2007 issuance of the securitization bonds.
Community Development Block Grants
In December 2005, the U.S. Congress passed the Katrina Relief Bill, a hurricane aid package that includes $11.5 billion in Community Development Block Grants (CDBG) (for the states affected by Hurricanes Katrina, Rita, and Wilma) that allows state and local leaders to fund individual recovery priorities. The bill includes language that permits funding to be provided for infrastructure restoration.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
New Orleans
In March 2006, Entergy New Orleans provided a justification statement to state and local officials in connection with its pursuit of CDBG funds to mitigate Hurricane Katrina restoration costs that otherwise would be borne by customers. The statement included all the estimated costs of Hurricane Katrina damage, as well as a lost customer base component intended to help offset the need for storm-related rate increases. In October 2006, theGulf States Louisiana, Recovery Authority Board endorsed a resolution proposing to allocate $200 million in CDBG funds to Entergy New Orleans to defray gas and electric utility system repair costs in an effort to provide rate relief for Entergy New Orleans customers. The proposal was developed as an action plan amendment and published for public comment. State lawmakers approved the action plan in December 2006, and the U. S. Department of Housing and Urban Development approved it in February 2007. Entergy New Orleans filed applications seeking City Council certification of its storm-related costs incurred through December 2006. Entergy New Orleans supplemented this request to include the estimated future cost of the gas system rebuild.
In March 2007, the City Council certified that Entergy New Orleans incurred $205 million in storm-related costs through December 2006 that are eligible for CDBG funding under the state action plan, and certified Entergy New Orleans' estimated costs of $465 million for its gas system rebuild. In April 2007, Entergy New Orleans executed an agreement with the Louisiana Office of Community Development (OCD) under which $200 million of CDBG funds will be made available to Entergy New Orleans. Entergy New Orleans submitted the agreement to the bankruptcy court, which approved it on April 25, 2007. Entergy New Orleans received $180.8 million of CDBG funds in 2007.
Mississippi
In March 2006, the Governor of Mississippi signed a law that established a mechanism by which the MPSC could authorize and certify an electric utility financing order and the state could issue bonds to finance the costs of repairing damage caused by Hurricane Katrina to the systems of investor-owned electric utilities. Because of the passage of this law and the possibility of Entergy Mississippi obtaining CDBG funds for Hurricane Katrina storm restoration costs, in March 2006, the MPSC issued an order approving a Joint Stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provided for a review of Entergy Mississippi's total storm restoration costs in an Application for an Accounting Order proceeding. In June 2006, the MPSC issued an order certifying Entergy Mississippi's Hurricane Katrina restoration costs incurred through March 31, 2006 of $89 million, net of estimated insurance proceeds. Two days later, Entergy Mississippi filed a request with the Mississippi Development Authority for $89 million of CDBG funding for reimbursement of its Hurricane Katrina infrastructure restoration costs. Entergy Mississippi also filed a Petition for Financing Order with the MPSC for authorization of state bond financing of $169 million for Hurricane Katrina restoration costs and future storm costs. The $169 million amount included the $89 million of Hurricane Katrina restoration costs plus $80 million to build Entergy Mississippi's storm damage reserve for the future. Entergy Mississippi's filing stated that the amount actually financed through the state bonds would be net of any CDBG funds that Entergy Mississippi received.
In October 2006, the Mississippi Development Authority approved for payment and Entergy Mississippi received $81 million in CDBG funding for Hurricane Katrina costs. The MPSC then issued a financing order authorizing the issuance of state bonds to finance $8 million of Entergy Mississippi's certified Hurricane Katrina restoration costs and $40 million for an increase in Entergy Mississippi's storm damage reserve. $30 million of the storm damage reserve was set aside in a restricted account. A Mississippi state entity issued the bonds in May 2007, and Entergy Mississippi received proceeds of $48 million. Entergy Mississippi doesLouisiana do not report the bonds on itstheir balance sheetsheets because the bonds are the obligation of the state entity,LCDA, and there is no recourse against Entergy, MississippiEntergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agents for the state.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cash Flow Activity
As shown in Entergy'sEntergy’s Statements of Cash Flows, cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2009 | | 2008 | | 2007 |
| | | | (In Millions) |
| | | | | | | | |
| Cash and cash equivalents at beginning of period | | $1,920 | | $1,253 | | $1,016 |
| | | | | | | |
| Effect of reconsolidating Entergy New Orleans in 2007 | | - | | - | | 17 |
| | | | | | | |
| Cash flow provided by (used in): | | | | | | |
| | Operating activities | | 2,933 | | 3,324 | | 2,560 |
| | Investing activities | | (2,094) | | (2,590) | | (2,118) |
| | Financing activities | | (1,048) | | (70) | | (222) |
| Effect of exchange rates on cash and cash equivalents | | (1) | | 3 | | - |
| | Net increase (decrease) in cash and cash equivalents | | (210) | | 667 | | 220 |
| | | | | | | | |
| Cash and cash equivalents at end of period | | $1,710 | | $1,920 | | $1,253 |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 694 | | | $ | 1,295 | | | $ | 1,710 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 2,940 | | | | 3,128 | | | | 3,926 | |
| Investing activities | | | (3,639 | ) | | | (3,447 | ) | | | (2,574 | ) |
| Financing activities | | | 538 | | | | (282 | ) | | | (1,767 | ) |
| Net decrease in cash and cash equivalents | | | (161 | ) | | | (601 | ) | | | (415 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 533 | | | $ | 694 | | | $ | 1,295 | |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Operating Activities
Operating Cash Flow Activity
20092012 Compared to 20082011
Entergy's net cash flow provided by operating activities decreased by $391$188 million in 20092012 compared to 20082011 primarily due to:
| · | the decrease in Entergy Wholesale Commodities net revenue that is discussed previously; |
| · | Hurricane Isaac storm restoration spending in 2012; |
| · | income tax payments of $49.2 million in 2012 compared to income tax refunds of $2 million in 2011; and |
| · | a refund of $30.6 million, including interest, paid to AmerenUE in June 2012. The FERC ordered Entergy Arkansas to refund to AmerenUE the rough production cost equalization payments previously collected. See Note 2 to the financial statements for further discussion of the FERC order. |
These decreases were partially offset by a decrease of $230 million in pension contributions. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
2011 Compared to 2010
Entergy's net cash provided by operating activities decreased by $798 million in 2011 compared to 2010 primarily due to the receipt in 2008July 2010 of $954$703 million from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings Arkansas ice storm restoration spending, and increases in nuclear refueling outage spending and spin-off costs at Non-Utility Nuclear. These factors were partially offset by a decrease of $94 million in income tax payments, a decrease of $155 million in pension contributions at Utility and Non-Utility Nuclear, increased collection of fuel costs, and higher spending in 2008 onfor Hurricane Gustav and Hurricane IkeIke. The Act 55 storm restoration.cost financings are discussed in Note 2 to the financial statements. The decrease in Entergy Wholesale Commodities net revenue that is discussed above also contributed to the decrease in operating cash flow.
2008Investing Activities
2012 Compared to 20072011
Entergy'sNet cash flow provided by operatingused in investing activities increased by $765$192 million in 20082012 compared to 2007. Following2011 primarily due to an increase in construction expenditures, primarily in the Utility business resulting from Hurricane Isaac restoration spending, the uprate project at Grand Gulf, the Ninemile Unit 6 self-build project, and the Waterford 3 steam generator replacement project in 2012. Entergy’s construction spending plans for 2013 through 2015 are discussed further in the “ Capital Expenditure Plans and Other Uses of Capital” above.
This increase was partially offset by:
| · | a decrease of $190 million in payments for the purchase of plants resulting from the purchase of the Hot Spring Energy Facility by Entergy Arkansas for approximately $253 million in November 2012, the purchase of the Hinds Energy Facility by Entergy Mississippi for approximately $206 million in November 2012, the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in April 2011, and the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in December 2011. These transactions are described in more detail in Note 15 to the financial statements; |
| · | proceeds received from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and |
| · | a decrease in nuclear fuel purchases because of variations from year to year in the timing and pricing of fuel reload requirements, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2011 Compared to 2010
Net cash flows from operatingused in investing activities by segment:increased $873 million in 2011 compared to 2010 primarily due to:
| · | Utility provided $2,379the purchase of the Acadia Power Plant by Entergy Louisiana for approximately $300 million in cash from operating activitiesApril 2011, the purchase of the Rhode Island State Energy Center for approximately $346 million by an Entergy Wholesale Commodities subsidiary in 2008 compared to providing $1,809December 2011, and the sale of an Entergy Wholesale Commodities subsidiary’s ownership interest in the Harrison County Power Project for proceeds of $219 million in 2007 primarily due to proceeds of $954 million received from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financings. The Act 55 storm cost financings2010. These transactions are discusseddescribed in more detail in Note 215 to the financial statements. A decrease in income tax payments of $290 million also contributed to the increase. Offsetting these factors were the net effect of Hurricane Gustav and Hurricane Ike which reduced operating cash flow by $444 million in 2008 as a result of costs associated with system repairs and lower revenues due to customer outages, the receipt of $181 million of Community Development Block Grant funds by Entergy New Orleans in 2007, and a $100 million increase in pension contributions in 2008.statements; |
| · | Non-Utility Nuclear provided $1,255 million in cash from operating activities in 2008 compared to providing $880 million in 2007, primarily due to an increase in net revenue, partially offset by an increasenuclear fuel purchases because of variations from year to year in operationthe timing and maintenance costs, bothpricing of which are discussed in "Resultsfuel reload requirements, material and services deliveries, and the timing of Operations."cash payments during the nuclear fuel cycle; and |
| · | Parent & Other used $310a slight increase in construction expenditures, including spending resulting from April 2011 storms that caused damage to transmission and distribution lines, equipment, poles, and other facilities, primarily in Arkansas. The capital cost of repairing that damage was approximately $55 million. |
These increases were offset by the investment in 2010 of a total of $290 million in Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm reserve escrow accounts as a result of their Act 55 storm cost financings, which are discussed in Note 2 to the financial statements.
Financing Activities
2012 Compared to 2011
Entergy’s financing activities provided $538 million of cash in 2012 compared to using $282 million of cash in 2011 primarily due to the following activity:
| · | long-term debt activity provided approximately $348 million of cash in 2012 compared to $554 million of cash in 2011. The most significant long-term debt activity in 2012 included the net issuance of $1.1 billion of long-term debt at the Utility operating companies and System Energy, the issuance of $500 million of senior notes by Entergy Corporation, and Entergy Corporation decreasing borrowings outstanding on its long-term credit facility by $1.1 billion. Entergy Corporation issued $665 million of commercial paper in 2012 to repay borrowings on its long-term credit facility; |
| · | Entergy repurchasing $235 million of its common stock in 2011, as discussed below; |
| · | a net increase in 2012 of $51 million in cash in operating activities in 2008 compared to using $129short-term borrowings by the nuclear fuel company variable interest entities; and |
| · | $51 million in 2007 primarily dueproceeds from the sale to an increasea third party in income taxes paid2012 of $69 million and outside services costsa portion of $69 million related to the planned spin-off of the Non-Utility Nuclear business.Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests. |
For the details of Entergy's commercial paper program and the nuclear fuel company variable interest entities’ short-term borrowings, see Note 4 to the financial statements. For the details of Entergy’s long-term debt outstanding, see Note 5 to the financial statements.
2011 Compared to 2010
Net cash used in financing activities decreased $1,485 million in 2011 compared to 2010 primarily because long-term debt activity provided approximately $554 million of cash in 2011 and used approximately $307 million of cash in 2010. The most significant long-term debt activity in 2011 included the issuance of $207 million of securitization bonds by a subsidiary of Entergy Louisiana, the issuance of $200 million of first mortgage bonds by Entergy Louisiana, and Entergy Corporation increasing the borrowings outstanding on its 5-year credit facility by $288 million. For the details of Entergy’s long-term debt outstanding on December 31, 2011 and 2010 see Note 5 to the financial statements. In addition to the long-term debt activity, Entergy Corporation repurchased $235 million of its common stock in 2011 and repurchased $879 million of its common stock in 2010. Entergy’s stock repurchases are discussed further in the “Capital Expenditure Plans and Other Uses of Capital - Dividends and Stock Repurchases” section above.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Investing Activities
2009 Compared to 2008
Net cash used in investing activities decreased by $496 million in 2009 compared to 2008. The following significant investing cash flow activity occurred in 2009 and 2008:
· | Construction expenditures were $281 million lower in 2009 than in 2008 primarily due to Hurricane Gustav and Hurricane Ike restoration spending in 2008. |
· | In March 2008, Entergy Gulf States Louisiana purchased the Calcasieu Generating Facility, a 322 MW simple-cycle, gas-fired power plant located near the city of Sulphur in southwestern Louisiana, for approximately $56 million. |
· | In September 2008, Entergy Arkansas purchased the Ouachita Plant, a 789 MW gas-fired plant located 20 miles south of the Arkansas state line near Sterlington, Louisiana, for approximately $210 million (In November 2009, Entergy Arkansas sold one-third of the plant to Entergy Gulf States Louisiana). |
· | Receipt in 2009 of insurance proceeds from Entergy Texas' Hurricane Ike claim and in 2008 of insurance proceeds from Entergy New Orleans' Hurricane Katrina claim. |
· | The investment of a net total of $45 million in escrow accounts for construction projects in 2008 and the withdrawal of $36 million of those funds from escrow accounts in 2009. |
2008 Compared to 2007
Net cash used in investing activities increased by $472 million in 2008 compared to 2007. The following activity is notable in comparing 2008 to 2007:
· | Construction expenditures were $634 million higher in 2008 than in 2007, primarily due to storm restoration spending caused by Hurricane Gustav and Hurricane Ike and increased spending on various projects by the Utility that are discussed further in "Capital Expenditure Plans and Other Uses of Capital" above. |
· | In April 2007, Non-Utility Nuclear purchased the 798 MW Palisades nuclear power plant located near South Haven, Michigan for a net cash payment of $336 million. |
· | In March 2008, Entergy Gulf States Louisiana purchased the Calcasieu Generating Facility, a 322 MW simple-cycle, gas-fired power plant located near the city of Sulphur in southwestern Louisiana, for approximately $56 million. |
· | In September 2008, Entergy Arkansas purchased the Ouachita Plant, a 789 MW gas-fired plant located 20 miles south of the Arkansas state line near Sterlington, Louisiana, for approximately $210 million. |
· | Non-Utility Nuclear made a $72 million payment to NYPA in 2008 under the value sharing agreements associated with the acquisition of the FitzPatrick and Indian Point 3 power plants. See Note 15 to the financial statements for additional discussion of the value sharing agreements. |
· | The investment of a net total of $45 million in escrow accounts for construction projects in 2008. |
· | Entergy Mississippi realized proceeds in 2007 from $100 million of investments held in trust that were received from a bond issuance in 2006 and used to redeem bonds in 2007. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Financing Activities
2009 Compared to 2008
Net cash used in financing activities increased $978 million in 2009 compared to 2008. The following significant financing cash flow activity occurred in 2009 and 2008:
· | Entergy Corporation decreased the net borrowings under its credit facility by $671 million in 2009 compared to increasing the net borrowings under its credit facility by $986 million in 2008. See Note 4 to the financial statements for a description of the Entergy Corporation credit facility. |
· | Entergy Texas issued $500 million of 7.125% Series mortgage bonds in January 2009 and used a portion of the proceeds to repay $70.8 million in long-term debt prior to maturity. |
· | Entergy Texas issued $150 million of 7.875% Series mortgage bonds in May 2009. |
· | Entergy Mississippi issued $150 million of 6.64% Series first mortgage bonds in June 2009. |
· | Entergy Gulf States Louisiana issued $300 million of 5.59% Series first mortgage bonds in October 2009. |
· | Entergy Louisiana issued $400 million of 5.40% Series first mortgage bonds in November 2009. |
· | A subsidiary of Entergy Texas issued $545.9 million of securitization bonds in November 2009. See Note 5 to the financial statements for additional information regarding the securitization bonds. |
· | Entergy Gulf States Louisiana paid, at or prior to maturity, $721.2 million in 2009 and $675.8 million in 2008 of long term debt, including $602.2 million in 2009 and $309.1 million in 2008 paid by Entergy Texas under the debt assumption agreement; |
· | Entergy Arkansas issued $300 million of 5.4% Series first mortgage bonds in July 2008. |
· | Entergy Louisiana issued $300 million of 6.5% Series first mortgage bonds in August 2008. |
· | Entergy Louisiana repurchased, prior to maturity, $60 million of Auction Rate governmental bonds in April 2008. |
· | Entergy New Orleans paid, at maturity, its $30 million 3.875% Series first mortgage bonds in August 2008. |
· | The Utility operating companies decreased the borrowings outstanding on their long-term credit facilities by $100 million in 2009 and increased the borrowings outstanding on their long-term credit facilities by $100 million in 2008. |
· | Entergy Corporation paid $267 million of notes payable in 2009 and $237 million of notes payable in 2008 at their maturities. |
· | Entergy Corporation repurchased $613 million of its common stock in 2009 and repurchased $512 million of its common stock in 2008. |
2008 Compared to 2007
Net cash used in financing activities decreased $151 million in 2008 compared to 2007. The following activity is notable in comparing 2008 to 2007:
· | Entergy Corporation increased the net borrowings under its revolving credit facility by $986 million in 2008 and by $1,431 million in 2007. See Note 4 to the financial statements for a description of the Entergy Corporation credit facility. |
· | Entergy Arkansas issued $300 million of 5.40% Series first mortgage bonds in July 2008. |
· | Entergy Louisiana issued $300 million of 6.50% Series first mortgage bonds in August 2008. |
· | Entergy Louisiana repurchased, prior to maturity, $60 million of Auction Rate governmental bonds in April 2008. |
· | Entergy New Orleans paid, at maturity, its $30 million 3.875% Series first mortgage bonds in August 2008. |
· | Under the terms of the debt assumption agreement between Entergy Texas and Entergy Gulf States Louisiana that is discussed in Note 5 to the financial statements, Entergy Texas paid at maturity $309.1 million of Entergy Gulf States Louisiana first mortgage bonds in 2008. |
· | The Utility operating companies increased the borrowings outstanding on their long-term credit facilities by $100 million in 2008. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
· | A subsidiary of Entergy Texas issued $329.5 million of securitization bonds in June 2007. See Note 5 to the financial statements for additional information regarding the securitization bonds. |
· | Entergy Corporation paid $237 million of notes payable at their maturities in 2008. |
· | Entergy Mississippi redeemed $100 million of First Mortgage Bonds in 2007. |
· | Entergy Corporation repurchased $512 million of its common stock in 2008 and $1,216 million of its common stock in 2007. |
· | Entergy Corporation increased the dividend on its common stock in the third quarter 2007. The quarterly dividend was $0.54 per share for the first two quarters of 2007 and $0.75 per share for each quarter since then. |
Rate, Cost-recovery, and Other Regulation
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that the Utility operating companies and System Energy charge for their services significantly influence Entergy'sEntergy’s financial position, results of operations, and liquidity. These companies are regulated and the rates charged to their customers are determined in regulatory proceedings. Governmental agencies, including the APSC, the City Council, the LPSC, the MPSC, the PUCT, and the FERC, are primarily responsible for approval of the rates charged to customers. Following is a summary of the Utility operating companies'companies’ authorized returns on common equity. equity:
Company | | Authorized Return on Common Equity |
| | |
Entergy Arkansas | | 10.2% |
| | |
| Entergy Gulf States Louisiana | | 9.9%-11.4% Electric; 10.0%-11.0% Gas |
| | |
Entergy Louisiana | | 9.45% - 11.05% |
| | |
| Entergy Mississippi | | 9.88% - 12.01% |
| | |
| Entergy New Orleans | | 10.7% - 11.5% Electric; 10.25% - 11.25% Gas |
| | |
Entergy Texas | | 9.8% |
The Utility operating companies' companies’ base rate, fuel and purchased power cost recovery, and storm cost recovery proceedings are discussed in Note 2 to the financial statements.
Federal Regulation
Independent Coordinator of Transmission
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs. In November 2006, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the ICT did not transfer control of the Entergy transmission system to the ICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
Company· | granting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | Authorized Returndeveloping a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on Common Equity (ROE) |
| | | |
the Entergy Arkansas | | | 9.9% |
| | | |
Entergy Gulf States Louisiana | | | 9.9%-11.4% (electric)
10.0%-11.0% (gas)
|
| | | |
Entergy Louisiana
| | | 9.45%-11.05% |
| | | |
Entergy Mississippi | | | 11.91%-14.42% |
| | | |
Entergy New Orleans | | | 10.7%-11.5% (electric)
10.25%-11.25% (gas)
|
| | | |
Entergy Texas
| | | 10.0% (stipulated asSystem for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a reasonable ROE in rate case settlement) |
| | | |
System Energy
| | | 10.94%detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
Federal RegulationThe FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy exchangesallocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy'sEnergy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement ProceedingsParticipation
Production Cost Equalization Proceeding CommencedCiting its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the joint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the public interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. |
The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
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National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for 2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $163.3 million in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions.
| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority. |
Litigation
Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Uncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2012, which is included herein on pages 416 through 423.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2012. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation |
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc. |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
ALYSON M. MOUNT Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. | WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc. |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,302,079 | | | $ | 11,229,073 | | | $ | 11,487,577 | | | $ | 10,745,650 | | | $ | 13,093,756 | |
| Income from continuing operations | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | | | $ | 1,251,050 | | | $ | 1,240,535 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | | | $ | 6.39 | | | $ | 6.39 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | | | $ | 6.30 | | | $ | 6.20 | |
| Dividends declared per share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | | | $ | 3.00 | | | $ | 3.00 | |
| Return on common equity | | | 9.33 | % | | | 15.43 | % | | | 14.61 | % | | | 14.85 | % | | | 15.42 | % |
| Book value per share, year-end | | $ | 51.72 | | | $ | 50.81 | | | $ | 47.53 | | | $ | 45.54 | | | $ | 42.07 | |
| Total assets | | $ | 43,202,502 | | | $ | 40,701,699 | | | $ | 38,685,276 | | | $ | 37,561,953 | | | $ | 36,616,818 | |
| Long-term obligations (1) | | $ | 12,141,370 | | | $ | 10,268,645 | | | $ | 11,575,973 | | | $ | 11,277,314 | | | $ | 11,734,411 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 3,022 | | | $ | 3,369 | | | $ | 3,375 | | | $ | 2,999 | | | $ | 3,610 | |
| Commercial | | | 2,174 | | | | 2,333 | | | | 2,317 | | | | 2,184 | | | | 2,735 | |
| Industrial | | | 2,034 | | | | 2,307 | | | | 2,207 | | | | 1,997 | | | | 2,933 | |
| Governmental | | | 198 | | | | 205 | | | | 212 | | | | 204 | | | | 248 | |
| Total retail | | | 7,428 | | | | 8,214 | | | | 8,111 | | | | 7,384 | | | | 9,526 | |
| Sales for resale | | | 179 | | | | 216 | | | | 389 | | | | 206 | | | | 325 | |
| Other | | | 264 | | | | 244 | | | | 241 | | | | 290 | | | | 222 | |
| Total | | $ | 7,871 | | | $ | 8,674 | | | $ | 8,741 | | | $ | 7,880 | | | $ | 10,073 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 34,664 | | | | 36,684 | | | | 37,465 | | | | 33,626 | | | | 33,047 | |
| Commercial | | | 28,724 | | | | 28,720 | | | | 28,831 | | | | 27,476 | | | | 27,340 | |
| Industrial | | | 41,181 | | | | 40,810 | | | | 38,751 | | | | 35,638 | | | | 37,843 | |
| Governmental | | | 2,435 | | | | 2,474 | | | | 2,463 | | | | 2,408 | | | | 2,379 | |
| Total retail | | | 107,004 | | | | 108,688 | | | | 107,510 | | | | 99,148 | | | | 100,609 | |
| Sales for resale | | | 3,200 | | | | 4,111 | | | | 4,372 | | | | 4,862 | | | | 5,401 | |
| Total | | | 110,204 | | | | 112,799 | | | | 111,882 | | | | 104,010 | | | | 106,010 | |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,326 | | | $ | 2,414 | | | $ | 2,566 | | | $ | 2,711 | | | $ | 2,794 | |
| Billed Electric Energy Sales (GWh) | | | 46,178 | | | | 43,497 | | | | 42,934 | | | | 43,743 | | | | 44,875 | |
| | | | | | | | | | | | | | | | | | | | | |
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To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 27, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,870,649 | | | $ | 8,673,517 | | | $ | 8,740,637 | |
| Natural gas | | | 130,836 | | | | 165,819 | | | | 197,658 | |
| Competitive businesses | | | 2,300,594 | | | | 2,389,737 | | | | 2,549,282 | |
| TOTAL | | | 10,302,079 | | | | 11,229,073 | | | | 11,487,577 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,036,835 | | | | 2,492,714 | | | | 2,518,582 | |
| Purchased power | | | 1,255,800 | | | | 1,564,967 | | | | 1,659,416 | |
| Nuclear refueling outage expenses | | | 245,600 | | | | 255,618 | | | | 256,123 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Other operation and maintenance | | | 3,045,392 | | | | 2,867,758 | | | | 2,969,402 | |
| Decommissioning | | | 184,760 | | | | 190,595 | | | | 211,736 | |
| Taxes other than income taxes | | | 557,298 | | | | 536,026 | | | | 534,299 | |
| Depreciation and amortization | | | 1,144,585 | | | | 1,102,202 | | | | 1,069,894 | |
| Other regulatory charges - net | | | 175,104 | | | | 205,959 | | | | 44,921 | |
| TOTAL | | | 9,000,898 | | | | 9,215,839 | | | | 9,264,373 | |
| | | | | | | | | | | | | |
| Gain on sale of business | | | - | | | | - | | | | 44,173 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 1,301,181 | | | | 2,013,234 | | | | 2,267,377 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 92,759 | | | | 84,305 | | | | 59,381 | |
| Interest and investment income | | | 127,776 | | | | 128,994 | | | | 184,077 | |
| Miscellaneous - net | | | (53,214 | ) | | | (59,271 | ) | | | (48,124 | ) |
| TOTAL | | | 167,321 | | | | 154,028 | | | | 195,334 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 606,596 | | | | 551,521 | | | | 610,146 | |
| Allowance for borrowed funds used during construction | | | (37,312 | ) | | | (37,894 | ) | | | (34,979 | ) |
| TOTAL | | | 569,284 | | | | 513,627 | | | | 575,167 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 899,218 | | | | 1,653,635 | | | | 1,887,544 | |
| | | | | | | | | | | | | |
| Income taxes | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | |
| Dividends declared per common share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 177,324,813 | | | | 177,430,208 | | | | 186,010,452 | |
| Diluted average number of common shares outstanding | | | 177,737,565 | | | | 178,370,695 | | | | 187,814,235 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | | | | | | | |
| (net of tax expense (benefit) of ($55,750), $34,411, and ($7,088) | | | (97,591 | ) | | | 71,239 | | | | (11,685 | ) |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax benefit of $61,223, $131,198, and $14,387) | | | (91,157 | ) | | | (223,090 | ) | | | (8,527 | ) |
| Net unrealized investment gains | | | | | | | | | | | | |
| (net of tax expense of $61,104, $19,368, and $51,130) | | | 63,609 | | | | 21,254 | | | | 57,523 | |
| Foreign currency translation | | | | | | | | | | | | |
| (net of tax expense (benefit) of $275, $192, and ($182)) | | | 508 | | | | 357 | | | | (338 | ) |
| Other comprehensive income (loss) | | | (124,631 | ) | | | (130,240 | ) | | | 36,973 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | | 743,732 | | | | 1,237,132 | | | | 1,307,278 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| Comprehensive Income Attributable to Entergy Corporation | | $ | 722,042 | | | $ | 1,216,199 | | | $ | 1,287,215 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 1,771,649 | | | | 1,745,455 | | | | 1,705,331 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (26,479 | ) | | | (280,029 | ) | | | 718,987 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Gain on sale of business | | | - | | | | - | | | | (44,173 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (14,202 | ) | | | 28,091 | | | | (99,640 | ) |
| Fuel inventory | | | (11,604 | ) | | | 5,393 | | | | (10,665 | ) |
| Accounts payable | | | (6,779 | ) | | | (131,970 | ) | | | 216,635 | |
| Prepaid taxes and taxes accrued | | | 55,484 | | | | 580,042 | | | | (116,988 | ) |
| Interest accrued | | | 1,152 | | | | (34,172 | ) | | | 17,651 | |
| Deferred fuel costs | | | (99,987 | ) | | | (55,686 | ) | | | 8,909 | |
| Other working capital accounts | | | (151,989 | ) | | | 41,875 | | | | (160,326 | ) |
| Changes in provisions for estimated losses | | | (24,808 | ) | | | (11,086 | ) | | | 265,284 | |
| Changes in other regulatory assets | | | (398,428 | ) | | | (673,244 | ) | | | 339,408 | |
| Changes in pensions and other postretirement liabilities | | | 644,099 | | | | 962,461 | | | | (80,844 | ) |
| Other | | | (21,710 | ) | | | (415,685 | ) | | | (103,793 | ) |
| Net cash flow provided by operating activities | | | 2,940,285 | | | | 3,128,817 | | | | 3,926,081 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (2,674,650 | ) | | | (2,040,027 | ) | | | (1,974,286 | ) |
| Allowance for equity funds used during construction | | | 96,131 | | | | 86,252 | | | | 59,381 | |
| Nuclear fuel purchases | | | (557,960 | ) | | | (641,493 | ) | | | (407,711 | ) |
| Payment for purchase of plant | | | (456,356 | ) | | | (646,137 | ) | | | - | |
| Proceeds from sale of assets and businesses | | | - | | | | 6,531 | | | | 228,171 | |
| Insurance proceeds received for property damages | | | - | | | | - | | | | 7,894 | |
| Changes in securitization account | | | 4,265 | | | | (7,260 | ) | | | (29,945 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | (72,000 | ) |
| Payments to storm reserve escrow account | | | (8,957 | ) | | | (6,425 | ) | | | (296,614 | ) |
| Receipts from storm reserve escrow account | | | 27,884 | | | | - | | | | 9,925 | |
| Decrease (increase) in other investments | | | 15,175 | | | | (11,623 | ) | | | 24,956 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 109,105 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,074,055 | | | | 1,360,346 | | | | 2,606,383 | |
| Investment in nuclear decommissioning trust funds | | | (2,196,489 | ) | | | (1,475,017 | ) | | | (2,730,377 | ) |
| Net cash flow used in investing activities | | | (3,639,797 | ) | | | (3,446,853 | ) | | | (2,574,223 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | |
| Long-term debt | | | 3,478,361 | | | | 2,990,881 | | | | 3,870,694 | |
| Mandatorily redeemable preferred membership units of subsidiary | | | 51,000 | | | | - | | | | - | |
| Treasury stock | | | 62,886 | | | | 46,185 | | | | 51,163 | |
| Retirement of long-term debt | | | (3,130,233 | ) | | | (2,437,372 | ) | | | (4,178,127 | ) |
| Repurchase of common stock | | | - | | | | (234,632 | ) | | | (878,576 | ) |
| Redemption of subsidiary common and preferred stock | | | - | | | | (30,308 | ) | | | - | |
| Changes in credit borrowings and commercial paper - net | | | 687,675 | | | | (6,501 | ) | | | (8,512 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (589,209 | ) | | | (589,605 | ) | | | (603,854 | ) |
| Preferred stock | | | (22,329 | ) | | | (20,933 | ) | | | (20,063 | ) |
| Net cash flow provided by (used in) financing activities | | | 538,151 | | | | (282,285 | ) | | | (1,767,275 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (508 | ) | | | 287 | | | | 338 | |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (161,869 | ) | | | (600,034 | ) | | | (415,079 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 694,438 | | | | 1,294,472 | | | | 1,709,551 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 532,569 | | | $ | 694,438 | | | $ | 1,294,472 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 546,125 | | | $ | 532,271 | | | $ | 534,004 | |
| Income taxes | | $ | 49,214 | | | $ | (2,042 | ) | | $ | 32,144 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 112,992 | | | $ | 81,468 | |
| Temporary cash investments | | | 419,577 | | | | 612,970 | |
| Total cash and cash equivalents | | | 532,569 | | | | 694,438 | |
| Securitization recovery trust account | | | 46,040 | | | | 50,304 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 568,871 | | | | 568,558 | |
| Allowance for doubtful accounts | | | (31,956 | ) | | | (31,159 | ) |
| Other | | | 161,408 | | | | 166,186 | |
| Accrued unbilled revenues | | | 303,392 | | | | 298,283 | |
| Total accounts receivable | | | 1,001,715 | | | | 1,001,868 | |
| Deferred fuel costs | | | 150,363 | | | | 209,776 | |
| Accumulated deferred income taxes | | | 306,902 | | | | 9,856 | |
| Fuel inventory - at average cost | | | 213,831 | | | | 202,132 | |
| Materials and supplies - at average cost | | | 928,530 | | | | 894,756 | |
| Deferred nuclear refueling outage costs | | | 243,374 | | | | 231,031 | |
| System agreement cost equalization | | | 16,880 | | | | 36,800 | |
| Prepayments and other | | | 242,922 | | | | 291,742 | |
| TOTAL | | | 3,683,126 | | | | 3,622,703 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 46,738 | | | | 44,876 | |
| Decommissioning trust funds | | | 4,190,108 | | | | 3,788,031 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 256,039 | | | | 260,436 | |
| Other | | | 436,234 | | | | 416,423 | |
| TOTAL | | | 4,929,119 | | | | 4,509,766 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 41,944,567 | | | | 39,385,524 | |
| Property under capital lease | | | 935,199 | | | | 809,449 | |
| Natural gas | | | 353,492 | | | | 343,550 | |
| Construction work in progress | | | 1,365,699 | | | | 1,779,723 | |
| Nuclear fuel | | | 1,598,430 | | | | 1,546,167 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 46,197,387 | | | | 43,864,413 | |
| Less - accumulated depreciation and amortization | | | 18,898,842 | | | | 18,255,128 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 27,298,545 | | | | 25,609,285 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 742,030 | | | | 799,006 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $914,751 as of December 31, 2012 and $1,009,103 as of | | | | | | | | |
| December 31, 2011) | | | 5,025,912 | | | | 4,636,871 | |
| Deferred fuel costs | | | 172,202 | | | | 172,202 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Accumulated deferred income taxes | | | 37,748 | | | | 19,003 | |
| Other | | | 936,648 | | | | 955,691 | |
| TOTAL | | | 7,291,712 | | | | 6,959,945 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 718,516 | | | $ | 2,192,733 | |
| Notes payable and commercial paper | | | 796,002 | | | | 108,331 | |
| Accounts payable | | | 1,217,180 | | | | 1,069,096 | |
| Customer deposits | | | 359,078 | | | | 351,741 | |
| Taxes accrued | | | 333,719 | | | | 278,235 | |
| Accumulated deferred income taxes | | | 13,109 | | | | 99,929 | |
| Interest accrued | | | 184,664 | | | | 183,512 | |
| Deferred fuel costs | | | 96,439 | | | | 255,839 | |
| Obligations under capital leases | | | 3,880 | | | | 3,631 | |
| Pension and other postretirement liabilities | | | 95,900 | | | | 44,031 | |
| System agreement cost equalization | | | 25,848 | | | | 80,090 | |
| Other | | | 261,986 | | | | 283,531 | |
| TOTAL | | | 4,106,321 | | | | 4,950,699 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 8,311,756 | | | | 8,096,452 | |
| Accumulated deferred investment tax credits | | | 273,696 | | | | 284,747 | |
| Obligations under capital leases | | | 34,541 | | | | 38,421 | |
| Other regulatory liabilities | | | 898,614 | | | | 728,193 | |
| Decommissioning and asset retirement cost liabilities | | | 3,513,634 | | | | 3,296,570 | |
| Accumulated provisions | | | 362,226 | | | | 385,512 | |
| Pension and other postretirement liabilities | | | 3,725,886 | | | | 3,133,657 | |
| Long-term debt (includes securitization bonds of $973,480 as of | | | | | | | | |
| December 31, 2012 and $1,070,556 as of December 31, 2011) | | | 11,920,318 | | | | 10,043,713 | |
| Other | | | 577,910 | | | | 501,954 | |
| TOTAL | | | 29,618,581 | | | | 26,509,219 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 186,511 | | | | 186,511 | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2012 and in 2011 | | | 2,548 | | | | 2,548 | |
| Paid-in capital | | | 5,357,852 | | | | 5,360,682 | |
| Retained earnings | | | 9,704,591 | | | | 9,446,960 | |
| Accumulated other comprehensive loss | | | (293,083 | ) | | | (168,452 | ) |
| Less - treasury stock, at cost (76,945,239 shares in 2012 and | | | | | | | | |
| 78,396,988 shares in 2011) | | | 5,574,819 | | | | 5,680,468 | |
| Total common shareholders' equity | | | 9,197,089 | | | | 8,961,270 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 9,291,089 | | | | 9,055,270 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Common Shareholders’ Equity | | | | |
| | | Subsidiaries’ Preferred Stock | | | Common Stock | | | Treasury Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 94,000 | | | $ | 2,548 | | | $ | (4,727,167 | ) | | $ | 5,370,042 | | | $ | 8,043,122 | | | $ | (75,185 | ) | | $ | 8,707,360 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,063 | | | | - | | | | - | | | | - | | | | 1,250,242 | | | | - | | | | 1,270,305 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | 36,973 | | | | 36,973 | |
| Common stock repurchases | | | - | | | | - | | | | (878,576 | ) | | | - | | | | - | | | | - | | | | (878,576 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 80,932 | | | | (2,568 | ) | | | - | | | | - | | | | 78,364 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (603,963 | ) | | | - | | | | (603,963 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,063 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,063 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2010 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,524,811 | ) | | $ | 5,367,474 | | | $ | 8,689,401 | | | $ | (38,212 | ) | | $ | 8,590,400 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,933 | | | | - | | | | - | | | | - | | | | 1,346,439 | | | | - | | | | 1,367,372 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (130,240 | ) | | | (130,240 | ) |
| Common stock repurchases | | | - | | | | - | | | | (234,632 | ) | | | - | | | | - | | | | - | | | | (234,632 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 78,975 | | | | (6,792 | ) | | | - | | | | - | | | | 72,183 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (588,880 | ) | | | - | | | | (588,880 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,933 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,933 | ) |
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| Balance at December 31, 2011 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,680,468 | ) | | $ | 5,360,682 | | | $ | 9,446,960 | | | $ | (168,452 | ) | | $ | 9,055,270 | |
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| Consolidated net income (a) | | | 21,690 | | | | - | | | | - | | | | - | | | | 846,673 | | | | - | | | | 868,363 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (124,631 | ) | | | (124,631 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | $ | 105,649 | | | | (2,830 | ) | | | - | | | | - | | | | 102,819 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (589,042 | ) | | | - | | | | (589,042 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (21,690 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (21,690 | ) |
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| Balance at December 31, 2012 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,574,819 | ) | | $ | 5,357,852 | | | $ | 9,704,591 | | | $ | (293,083 | ) | | $ | 9,291,089 | |
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| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
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| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
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NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously-reported amounts have been reclassified to conform to current classifications, with no effect on net income or common shareholders’ (or members’) equity.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 9,588 | | | $ | 6,624 | | | $ | 2,964 | | | $ | - | |
Other | | | 2,878 | | | | 2,493 | | | | 385 | | | | - | |
| Transmission | | | 3,654 | | | | 3,619 | | | | 35 | | | | - | |
| Distribution | | | 6,561 | | | | 6,561 | | | | - | | | | - | |
| Other | | | 1,654 | | | | 1,416 | | | | 235 | | | | 3 | |
| Construction work in progress | | | 1,366 | | | | 973 | | | | 392 | | | | 1 | |
| Nuclear fuel | | | 1,598 | | | | 907 | | | | 691 | | | | - | |
| Property, plant, and equipment - net | | $ | 27,299 | | | $ | 22,593 | | | $ | 4,702 | | | $ | 4 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 8,635 | | | $ | 5,441 | | | $ | 3,194 | | | $ | - | |
Other | | | 2,431 | | | | 2,032 | | | | 399 | | | | - | |
| Transmission | | | 3,344 | | | | 3,309 | | | | 35 | | | | - | |
| Distribution | | | 6,157 | | | | 6,157 | | | | - | | | | - | |
| Other | | | 1,716 | | | | 1,463 | | | | 250 | | | | 3 | |
| Construction work in progress | | | 1,780 | | | | 1,420 | | | | 359 | | | | 1 | |
| Nuclear fuel | | | 1,546 | | | | 802 | | | | 744 | | | | - | |
| Property, plant, and equipment - net | | $ | 25,609 | | | $ | 20,624 | | | $ | 4,981 | | | $ | 4 | |
Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.
“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $230.4 million and $214.3 million as of December 31, 2012 and 2011, respectively.
Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2012 and 2011, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,073 | | | $ | 1,428 | | | $ | 2,180 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,943 | |
Other | | | 621 | | | | 286 | | | | 680 | | | | 545 | | | | (11 | ) | | | 371 | | | | - | |
| Transmission | | | 1,034 | | | | 573 | | | | 734 | | | | 581 | | | | 27 | | | | 642 | | | | 28 | |
| Distribution | | | 1,747 | | | | 939 | | | | 1,454 | | | | 1,065 | | | | 331 | | | | 1,025 | | | | - | |
| Other | | | 115 | | | | 187 | | | | 289 | | | | 201 | | | | 182 | | | | 106 | | | | 17 | |
| Construction work in progress | | | 206 | | | | 125 | | | | 405 | | | | 63 | | | | 11 | | | | 90 | | | | 40 | |
| Nuclear fuel | | | 304 | | | | 147 | | | | 204 | | | | - | | | | - | | | | - | | | | 253 | |
| Property, plant, and equipment - net | | $ | 5,100 | | | $ | 3,685 | | | $ | 5,946 | | | $ | 2,455 | | | $ | 540 | | | $ | 2,234 | | | $ | 2,281 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,034 | | | $ | 1,458 | | | $ | 1,561 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,388 | |
Other | | | 398 | | | | 286 | | | | 679 | | | | 350 | | | | (7 | ) | | | 325 | | | | - | |
| Transmission | | | 942 | | | | 500 | | | | 706 | | | | 510 | | | | 22 | | | | 624 | | | | 5 | |
| Distribution | | | 1,700 | | | | 856 | | | | 1,304 | | | | 1,009 | | | | 298 | | | | 990 | | | | - | |
| Other | | | 173 | | | | 192 | | | | 278 | | | | 206 | | | | 186 | | | | 110 | | | | 18 | |
| Construction work in progress | | | 120 | | | | 122 | | | | 559 | | | | 105 | | | | 14 | | | | 91 | | | | 358 | |
| Nuclear fuel | | | 273 | | | | 206 | | | | 165 | | | | - | | | | - | | | | - | | | | 158 | |
| Property, plant, and equipment - net | | $ | 4,640 | | | $ | 3,620 | | | $ | 5,252 | | | $ | 2,180 | | | $ | 513 | | | $ | 2,140 | | | $ | 1,927 | |
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2012 | | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
| 2011 | | 2.6% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.2% | | 2.8% |
| 2010 | | 2.9% | | 1.8% | | 2.4% | | 2.6% | | 3.1% | | 2.3% | | 2.9% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $142 million and $136 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.8 million and $2.7 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10 million and $9.8 million as of December 31, 2012 and 2011, respectively.
As of December 31, 2012, construction expenditures included in accounts payable are $56.3 million for Entergy Arkansas, $9.7 million for Entergy Gulf States Louisiana, $110.4 million for Entergy Louisiana, $4.8 million for Entergy Mississippi, $1.9 million for Entergy New Orleans, $8.6 million for Entergy Texas, and $13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2012, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $86 |
| | Common Facilities | | Coal | | | | 15.75% | | $33 | | $22 |
White Bluff | Units 1 and 2 | | Coal | | 1,659 | | 57.00% | | $498 | | $319 |
Ouachita (2) | Common Facilities | | Gas | | | | 66.67% | | $169 | | $142 |
Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 40.25% | | $250 | | $170 |
Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 15.92% | | $9 | | $3 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $142 | | $99 |
Ouachita (2) | Common Facilities | | Gas | | | | 33.33% | | $87 | | $73 |
| Entergy Louisiana - | | | | | | | | | | | |
| Acadia | Common Facilities | | Gas | | | | 50.00% | | $8 | | $- |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | 1,678 | | 25.00% | | $250 | | $140 |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 29.75% | | $180 | | $113 |
Roy S. Nelson | Unit 6 Common
Facilities | | Coal | | | | 11.77% | | $6 | | $2 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $107 | | $68 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,430(4) | | 90.00%(3) | | $4,557 | | $2,569 |
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Entergy Wholesale Commodities: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $69 | | $43 |
| Independence | Common
Facilities | | Coal | | | | 7.18% | | $16 | | $9 |
| Roy S. Nelson | Unit 6 | | Coal | | 540 | | 10.9% | | $104 | | $54 |
| Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 4.31% | | $2 | | $1 |
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| (1) | “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
| (3) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
| (4) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Earnings per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions, Except Per Share Data) | |
| | | | | | $/share | | | | | | $/share | | | | | | $/share | |
| Net income attributable to Entergy Corporation | | $ | 846.7 | | | | | | $ | 1,346.4 | | | | | | $ | 1,250.2 | | | | |
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| Basic earnings per average common share | | | 177.3 | | | $ | 4.77 | | | | 177.4 | | | $ | 7.59 | | | | 186.0 | | | $ | 6.72 | |
| Average dilutive effect of: | | | | | | | | | | | | | | | | | | | | | | | | |
Stock options | | | 0.3 | | | | (0.01 | ) | | | 1.0 | | | | (0.04 | ) | | | 1.8 | | | | (0.06 | ) |
Other equity plans | | | 0.1 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Diluted earnings per average common shares | | | 177.7 | | | $ | 4.76 | | | | 178.4 | | | $ | 7.55 | | | | 187.8 | | | $ | 6.66 | |
The calculation of diluted earnings per share excluded 7,164,319 options outstanding at December 31, 2012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over three years.
Accounting for the Effects of Regulation
Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, where specific recovery is not provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the portion of River Bend that is not rate-regulated, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.
Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| · | Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act; |
| · | Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and |
| · | Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states. |
In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.
In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.
In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the VPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.
Impairment
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs | Range | Weighted
Average |
| | |
| Weighted average cost of capital | 7.5%-8.0% | 7.8% |
| Long-term pre-tax operating margin (cash basis) | 6.1%-7.8% | 7.2% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management (whose preferred holders also had protective rights until the securities were repurchased in December 2011), are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets
Other Regulatory Assets
Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2012 and 2011:
Entergy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 422.6 | | | $ | 395.9 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 35.1 | | | | 12.4 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Gas hedging costs - recovered through fuel rates | | | 8.3 | | | | 30.3 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 2,866.3 | | | | 2,542.0 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 970.8 | | | | 996.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 155.7 | | | | 81.2 | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 95.9 | | | | 108.8 | |
| Other | | | 75.1 | | | | 44.4 | |
Total | | $ | 5,025.9 | | | $ | 4,636.9 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 210.2 | | | $ | 187.7 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 831.2 | | | | 768.3 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.3 | | | | 4.6 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 115.2 | | | | 114.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 31.5 | | | | 34.7 | |
| Other | | | 6.2 | | | | 4.0 | |
Entergy Arkansas Total | | $ | 1,221.6 | | | $ | 1,126.9 | |
Entergy Gulf States Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 6.1 | | | $ | 12.8 | |
Gas hedging costs - recovered through fuel rates | | | 2.6 | | | | 8.6 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 300.5 | | | | 231.3 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 18.9 | | | | 10.2 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.9 | | | | 11.6 | |
| Other | | | 13.1 | | | | 4.1 | |
Entergy Gulf States Louisiana Total | | $ | 409.7 | | | $ | 333.9 | |
Entergy Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 136.9 | | | $ | 125.8 | |
Gas hedging costs - recovered through fuel rates | | | 3.4 | | | | 12.4 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 475.6 | | | | 427.9 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 74.5 | | | | 9.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 17.6 | | | | 20.0 | |
| Other | | | 28.0 | | | | 20.3 | |
Entergy Louisiana Total | | $ | 913.6 | | | $ | 814.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 5.6 | | | $ | 5.3 | |
Gas hedging costs - recovered through fuel rates | | | 2.2 | | | | 7.8 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 57.4 | | | | 48.5 | |
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.8 | | | | 7.8 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 234.6 | | | | 221.1 | |
Provision for storm damages - recovered through retail rates | | | 9.2 | | | | 30.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.6 | | | | 10.7 | |
| Other | | | 8.3 | | | | 4.7 | |
Entergy Mississippi Total | | $ | 401.5 | | | $ | 393.4 | |
Entergy New Orleans
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 3.6 | | | $ | 3.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 29.9 | | | | 16.3 | |
Gas hedging costs - recovered through fuel rates | | | - | | | | 1.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 134.6 | | | | 127.6 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 15.1 | | | | 8.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 2.3 | | | | 2.6 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
| Other | | | 5.5 | | | | 5.9 | |
Entergy New Orleans Total | | $ | 202.0 | | | $ | 178.8 | |
Entergy Texas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 1.2 | | | $ | 1.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 11.5 | | | | 4.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 258.8 | | | | 244.9 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 737.9 | | | | 822.5 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.4 | | | | 10.8 | |
| Other | | | 13.6 | | | | 4.9 | |
Entergy Texas Total | | $ | 1,114.5 | | | $ | 1,178.1 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 58.9 | | | $ | 59.6 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 56.8 | | | | 11.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b) | | | 198.2 | | | | 197.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 15.6 | | | | 18.2 | |
| Other | | | 0.6 | | | | 0.6 | |
System Energy Total | | $ | 330.1 | | | $ | 287.8 | |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
| (b) | Does not earn a return on investment, but is offset by related liabilities. |
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Correction of Regulatory Asset for Income Taxes
In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and would not be recovered in the future.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a cumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.
The effect was also immaterial to the balance sheets, results of operations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Income Statement | | | | | | | | | | | | |
| Income taxes | | $ | 88,313 | | | $ | 89,736 | | | $ | 75,878 | | | $ | 92,297 | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Earnings applicable to common equity | | $ | 202,202 | | | $ | 200,779 | | | $ | 189,911 | | | $ | 173,492 | |
| | | | | | | | | | | | | | | | | |
| Statement of Cash Flows | | | | | | | | | | | | | | | | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | $ | (6,268 | ) | | $ | (4,845 | ) | | $ | 87,920 | | | $ | 104,339 | |
Changes in other regulatory assets | | $ | (80,027 | ) | | $ | (77,713 | ) | | $ | 114,528 | | | $ | 141,216 | |
Other operating activities | | $ | (35,248 | ) | | $ | (37,562 | ) | | $ | 30,717 | | | $ | 4,029 | |
| | | December 31, 2011 | |
| | | As previously reported | | | As corrected | |
| | | | | | | |
| Balance Sheet | | | | | | |
| Regulatory asset for income taxes - net | | $ | 249,058 | | | $ | 173,724 | |
Accumulated deferred income taxes - current | | $ | 5,427 | | | $ | 5,107 | |
Accumulated deferred income taxes and taxes accrued | | $ | 1,397,230 | | | $ | 1,368,563 | |
| Member’s equity | | $ | 1,439,733 | | | $ | 1,393,386 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Years Ended December 31, 2011 and 2010 | |
| | | Member’s Equity | | | Total Equity | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Statement of Changes in Equity | | | | | | |
| Balance at December 31, 2009 | | $ | 1,473,930 | | | $ | 1,445,425 | | | $ | 1,441,759 | | | $ | 1,413,254 | |
| 2010 Net income | | $ | 190,738 | | | $ | 174,319 | | | $ | 190,738 | | | $ | 174,319 | |
| Balance at December 31, 2010 | | $ | 1,539,517 | | | $ | 1,494,593 | | | $ | 1,509,213 | | | $ | 1,464,289 | |
| 2011 Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 203,027 | | | $ | 201,604 | |
| Balance at December 31, 2011 | | $ | 1,439,733 | | | $ | 1,393,386 | | | $ | 1,380,123 | | | $ | 1,333,776 | |
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2012 and 2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
| | | | | | | |
| Entergy Arkansas | | $ | 97.3 | | | $ | 209.8 | |
| Entergy Gulf States Louisiana (a) | | $ | 99.2 | | | $ | 2.9 | |
| Entergy Louisiana (a) | | $ | 94.6 | | | $ | 1.5 | |
| Entergy Mississippi | | $ | 26.5 | | | $ | (15.8 | ) |
| Entergy New Orleans (a) | | $ | 1.9 | | | $ | (7.5 | ) |
| Entergy Texas | | $ | (93.3 | ) | | $ | (64.7 | ) |
| (a) | 2012 and 2011 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana, and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2005 the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC’s January 2007 order in light of the arguments advanced in Entergy Arkansas’s rehearing petition and because the value for Entergy Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas’s rehearing request and the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. Testimony has been filed, and the APSC will decide the case based on the record in the proceeding, including the prefiled testimony.
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the attorney general’s suit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund was made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the PUCT a request to refund approximately $66 million, including interest, of fuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2009 Base Rate Filing
In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies'companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in the System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC will imposeimposed a bandwidth remedy by which each company'scompany’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC'sFERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year'syear’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies'companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC'sFERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC'sFERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas'Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the AEECArkansas Electric Energy Consumers appealed the FERC'sFERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit affirmedconcluded that the FERC's decision in most respects, butFERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings and reconsideration of its conclusionon these issues.
In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it was prohibiteddid have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from orderingSeptember 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and its determination to implementordered that the prospective bandwidth remedy commencing with calendar year 2006 production costs (with the first payments/receipts commencing in June 2007), rather than commencing the remedybegin on June 1, 2005. The D.C. Circuit concluded2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC had failed so farthat was filed in a December 2006 compliance filing and accepted by the proceedingFERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to offer a reasoned explanation regarding these issues. other Utility operating company customers.
In December 20092011, Entergy filed with the FERC established a paper hearing to determine whetherits compliance filing that provides the FERC had the authoritypayments and if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs byreceipts among the Utility operating companies.companies pursuant to the FERC’s October 2011 order. The FERC also deferred further action onfiling shows the question of whether it provided sufficient rationale for not ordering refunds, and whether it impermissibly delayed implementation offollowing payments/receipts among the bandwidth remedy, until resolution of this paper hearing.Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Management'sNotes to Financial Discussion and AnalysisStatements
Entergy's Utility Operating Companies' Compliance FilingEntergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
In April 2006,Calendar Year 2012 Production Costs
The liabilities and assets for the Utility operating companies filed withpreliminary estimate of the FERC their compliance filingpayments and receipts required to implement the provisionsFERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the FERC's decision. The filing amended the System Agreement to provide for the calculation of production costs, average production costs, and payments/receipts among the Utility operating companies tofor 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the extent required to maintain rough production cost equalization pursuant toUtility operating companies’ 2012 FERC Form 1s have been filed. Once the FERC's decision.calculation is completed, it will be filed at the FERC. The FERC acceptedlevel of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the compliance filing in November 2006, with limited modifications. Provisionsprice of alternative fuels, the operating characteristics of the compliance filingEntergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as approved by the FERC include: the first payments commenced in June 2007, rather than earlier; interest is not required on the unpaid balance; and any payments will be made over seven months, rather than 12. In April 2007, the FERC denied various requests for rehearing, with one exception regarding the issue of retrospective refunds. That issue will be addressed subsequent to the remanded proceeding involving the interruptible load decision discussed further below in this section under "Interruptible Load Proceeding."plant investment.
Rough Production Cost Equalization Rates
Each yearMay since 2007 Entergy has filed with the FERC the rates to implement the FERC'sFERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC'sFERC’s orders:
| | | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | 2007 Payments or (Receipts) Based on 2006 Costs | 2008 Payments or (Receipts) Based on 2007 Costs | 2009 Payments or (Receipts) Based on 2008 Costs | | | (In Millions) | |
| | ( In Millions) | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | $252 | $252 | $390 | | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States Louisiana | ($120) | ($124) | ($107) | | |
| Entergy Gulf States La. | | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | ($91) | ($36) | ($140) | | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | ($41) | ($20) | ($24) | | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | $- | ($7) | $- | | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | ($30) | ($65) | ($119) | | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
Management believes that any changes in the allocation of production costs resulting from the FERC's decision and related retail proceedings should result in similar rate changes for retail customers. The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See "“Fuel and purchased power cost recovery, Entergy Texas," in Note 2 to the financial statements” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that Entergy Texas is currently challenging regarding the rough production cost equalization payments that could resultresulted in $18.6 million of trapped costs between Entergy'sEntergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Based on the FERC's April 27, 2007 order on rehearing that is discussed above, in the second quarter 2007 Entergy Arkansas, recordedand, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas recordedrecord accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC's remedy based on calendar year 2006 production costs.FERC’s remedy. Entergy Arkansas, recordedand, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas recordedrecord corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The companies have followed this same accounting practice each year since then. The regulatory asset and liabilities are shown as "System“System Agreement cost equalization"equalization” on the respective balance sheets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ'sALJ’s initial decision concludes,concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas'Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ'sALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its current wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas' bandwidth payment. According to AmerenUE, Entergy Arkansas has sought to collect from AmerenUE approximately $14.5 million of the 2007 Entergy ArkansasArkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, of this amount, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC'sFERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, also filed with thealthough there are still FERC during 2007 certain proposed modifications todecisions pending in other System Agreement proceedings that could affect the rough production cost equalization calculation.payments and receipts. The FERC rejected certaindirected Entergy, within 45 days of the proposed modifications, accepted certainissuance of the proposed modifications without further proceedings, and set two of the proposed modifications for hearing and settlement procedures. With respect to the proceeding involving changes toa pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the production function,U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a hearing wasrehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in March 2008abeyance and that the ALJ issued an Initial Decision in June 2008 findingparties file motions to govern further proceedings within 30 days of the modifications proposed byFERC’s completion of the Utility operating companies to be just and reasonable. In January 2010 the FERC affirmed the ALJ's decision.ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units'units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas'Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana'sLouisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy'sEntergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. Entergy,In October 2011 the APSC,FERC issued an order on the LPSC, andALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the MPSC have submitted briefsUtility operating companies on exceptionsone issue in the proceeding, and2008 rate filing. Entergy made a compliance filing in December 2011 showing the matter has been submittedupdated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for decision.the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. OnIn July 27, 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in April 2010, withMarch 2011. Subsequently, in January 2011 the ALJ issued an initial decision scheduled for August 2010.order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 20092010 Production Costs
The liabilitiesIn May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and assets forthen held those procedures in abeyance pending FERC decisions in the preliminary estimate ofprior production cost proceedings currently before the payments and receipts required to implement the FERC's remedy basedFERC on calendar year 2009 production costs were recorded in December 2009, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2010:
| Payments or
(Receipts)
|
| (In Millions) |
| |
Entergy Arkansas | $70 |
Entergy Gulf States Louisiana | ($10) |
Entergy Louisiana | ($54) |
Entergy Mississippi | $- |
Entergy New Orleans | ($6) |
Entergy Texas | $- |
review.
The actual payments/receipts for 2010, based2012 Rate Filing Based on calendar year 2009 production costs, will not be calculated untilCalendar Year 2011 Production Costs
In May 2012, Entergy filed with the Utility operating companies' FERC Form 1s have been filed. Once the calculation is completed, it will be filed2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC. The level of any paymentsFERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and receipts is significantly affected by a number of factors, including, among others, weather,then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.FERC on review.
Interruptible Load ProceedingIndependent Coordinator of Transmission
In April 20072000 the U.S. CourtFERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of Appeals forindependent RTOs (regional transmission organizations). Delays in implementing the D.C. Circuit issued its opinion inFERC RTO order occurred due to a variety of reasons, including the LPSC's appeal of the FERC's March 2004fact that utility companies, other stakeholders, and April 2005 ordersfederal and state regulators have had to work to resolve various issues related to the treatment under the System Agreementestablishment of the Utility operating companies' interruptible loads.such RTOs. In its opinion, the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowingNovember 2006, the Utility operating companies to phase-ininstalled the effectsSouthwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation of the eliminationICT did not transfer control of the interruptible load over a 12-month period of time; (2) failedEntergy transmission system to adequately explain why refunds couldthe ICT. Instead, the ICT performs some, but not be ordered under Section 206(c)all, of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances untilfunctions performed by a later time. The D.C. Circuit remanded the mattertypical RTO, as well as certain functions unique to the FERC for a more considered determination onEntergy transmission system. In particular, the issue of refunds. The FERC issued its order on remand in September 2007, in whichICT was vested with responsibility for:
| · | granting or denying transmission service on the Utility operating companies’ transmission system. |
| · | administering the Utility operating companies’ OASIS node for purposes of processing and evaluating transmission service requests. |
| · | developing a base plan for the Utility operating companies’ transmission system and deciding whether costs of transmission upgrades should be rolled into the Utility operating companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
it directs| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy to make atransmission system. During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies’ capital investment in the transmission system, the Utility operating companies’ compliance filing removing all interruptible load fromwith the computationexisting North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of peak load responsibility commencing April 1, 2004transmission service across the system, and to issue any necessary refunds to reflect this change. In addition, the order directswhether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make refundssignificant amounts of economic purchases from the wholesale market for the period May 1995 through July 1996. Entergy, the APSC, the MPSC, and the City Council requested rehearingbenefit of the FERC's orderUtility operating companies’ retail customers. The Utility operating companies also explained that, as with other transmission systems, there are certain times during which congestion occurs on remand.the Utility operating companies’ transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies committed in their response to exploring and working on potential reforms or alternatives for the ICT arrangement. The Utility operating companies’ comments also recognized that NERC was in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC grantedmay also make other changes to transmission reliability standards. Changes to the reliability standards could result in increased capital expenditures by the Utility operating companies.
In 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, was formed to consider issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC conducted a cost/benefit analysis comparing the ICT arrangement to other transmission proposals, including participation in an RTO.
In November 2010 the FERC issued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to delayextend the paymentICT arrangement and to transition to MISO as the provider of refundsICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the period May 1995 through July 1996 until Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
30 days following a FERC order on rehearing.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC issuedregulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in September 2008 an order denying rehearing.the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The refunds were madeproceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies that owed refundsin their execution of their obligations under the System Agreement. See Note 2 to the Utility operating companies that were due a refund on October 15, 2008. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to customers as a resultfinancial statements for discussions of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter of 2009.litigation.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC's decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC's unopposed motion on June 24, 2009, and directed the FERC to file status reports at 60-day intervals beginning August 24, 2009. The D.C. Circuit also directed the parties to file motions to govern future proceedings in the case within 30 days of the completion of the FERC proceedings. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. Pursuant to the paper hearing schedule, initial briefs were filed on January 19, 2010 and reply briefs were filed on February 9, 2010.
Entergy Arkansas and Entergy MississippiOperating Company Notices of Termination of System Agreement Participation and Related APSC Investigation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC. Entergy Arkansas indicated, however, that a properly structured replacement agreement could be a viable alternative.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. The MPSC letter also requested that Entergy Mississippi advise the MPSC regarding the status of the Utility operating companies' effort to develop successor arrangements to the System Agreement and advise the MPSC regarding Entergy Mississippi's position with respect to withdrawal from the System Agreement. In November 2007, pursuant to the provisions of the System Agreement, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
OnIn February 2, 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to effectuate the termination ofterminate their participation in the Entergy System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas'Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas'Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas'Arkansas’s and, eventually, Entergy Mississippi's,Mississippi’s, departure from the System Agreement. Entergy Arkansas and Entergy Mississippi requested that the FERC accept the proposed notices of cancellation without further proceedings. Various parties intervened or filed protests in the proceeding, including the APSC, the LPSC, the MPSC, and the City Council.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96 month96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. TheIn February 2011, the FERC stated that it expected Entergydenied the LPSC’s and all interested parties to move forwardthe City Council’s rehearing requests. In September and develop detailsOctober 2012, the U.S. Court of all needed successor arrangementsAppeals for the D.C. Circuit denied the LPSC’s and encouraged Entergy to file its Section 205 filing for postthe City Council’s appeals of the FERC decisions. In January 2013, arrangements as soon as possible. Thethe LPSC and the City Council have requested rehearingfiled a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the FERC's decision.Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The LPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of control to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC had previously commenced an investigation, in 2004, into whether Entergy Arkansas' continued participation in the System Agreement is in the best interests of its customers. More than once in the investigation proceedingauthorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its president, Hugh McDonald, filed testimonyorder that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC in response to requestsproof of approval by the APSC. In addition, Mr. McDonald has appeared before the APSC on more than one occasion at public hearings for questioning. In December 2007, the APSC ordered Mr. McDonald to file testimony each monthappropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC detailing progress toward developmentproof of successor arrangements, beginning in March 2008,approval of the governance enhancements and Mr. McDonald has done so. In his September 2009 testimony Mr. McDonald reported to the APSC the resultsrequested a finding of a related study. According to the study total estimated cost to establish the systemscompliance and staff the organizations to perform the necessary planning and operating functions for a stand-aloneapproval of Entergy Arkansas operation are estimated at approximately $23 million, including $18 million to establish generation-related functions and $5 million to modify transmission-related information systems. Incremental costs for ongoing staffing and systems costs are estimated at approximately $8 million. Cost and implementation schedule estimates will continue to be re-evaluated and refined as additional, more detailed analysis is completed. The study did not assess the effect of stand-alone operation on Entergy Arkansas’ generation resource requirements. Entergy Arkansas expects it would take approximately two years to implement stand-alone operations for Entergy Arkansas.
In February 2010Arkansas's application. On November 21, 2012, the APSC issued an order announcingrequiring that MISO file a refocus“higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the form of sworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its ongoing investigation of Entergy Arkansas' post-System Agreement operation. The order describes the APSC's "stated purpose in opening this inquirytransmission owners, jointly submitting changes to conduct an investigation regarding the prudence of [Entergy Arkansas] entering into a successor ESA [Entergy System Agreement] as opposed to becoming a stand-alone utility upon its exit from the ESA, and whether [Entergy Arkansas], as a standalone utility, should join the SPP RTO. It is the [APSC's] intention to render a decision regarding the prudence of [Entergy Arkansas] entering into a successor ESA as opposed to becoming a stand-alone utility upon its exit from the ESA, as well as [Entergy Arkansas'] RTO participation by the end of calendar year 2010. In parallel with this Docket, the [APSC] will be actively involved and will be closely watching to see if any meaningful enhancement will be made to a new Enhanced Independent Coordinator of Transmission (“E-ICT") Agreement through the effortsAppendix K of the ETS [EntergyMISO Transmission System] stakeholders, Entergy,Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the newly formedjoint filing submitted to FERC on January 4, 2013, and federally-recognized E-RSC in 2010." The schedule set by the order includes evidentiary hearings in March and May 2010. The order directedasked that the existing docket investigatingAPSC find MISO in compliance with the conditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas' participation in the System Agreement be closed. For a discussion of Entergy's Independent Coordinator of Transmission and the E-RSC see "Independent Coordinator of Transmission" below.Arkansas’s application to join MISO.
LPSC and City Council Action Related to theOn January 23, 2013, Entergy Arkansas andfiled a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Mississippi NoticesArkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of TerminationEntergy Arkansas will not be successfully completed on time.
In lightSeptember 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities to MISO is in the noticespublic interest, subject to certain contingencies and conditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and the Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy ArkansasNew Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy MississippiLouisiana to terminate participation in the current System Agreement, in January 2008 the LPSC unanimously votedjoin MISO, subject to direct the LPSC Staff to begin evaluating the potential for a new agreement. Likewise, the New Orleans City Council opened a docket to gather information on progress towards a successor agreement.certain conditions.
June 2009 LPSC Complaint ProceedingEntergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as in the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the PUCT and agreed to by the settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In June 2009,December 2012 the LPSCPUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The FERC filings related to the terms and conditions of integrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to the E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for determining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine that certainwhether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Arkansas' salesGulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
Entergy’s initial filings with its retail regulators estimated that the transition and implementation costs of electric energyjoining the MISO RTO could be up to third parties: (a) violated the provisions$105 million if all of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC's complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response tojoin the complaint requesting thatMISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violationviability of the System Agreementalternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and failedlegal agreements, to produce any evidenceintegrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
FERC’s Division of imprudent action by the Entergy System. In their response,Investigations is conducting an investigation of certain issues relating to the Utility operating companies compliance with certain reliability standards related to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain functions. Entergy Services is in the process of responding to the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
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Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future net income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks.
| · | The commodity price risk associated with the sale of electricity by the Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy’s investments in nuclear plant decommissioning trust funds, particularly in the Entergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy’s debt outstanding. |
The Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Power Generation
As a wholesale generator, Entergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Entergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Entergy Wholesale Commodities sells unforced capacity, which allows load-serving entities to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Entergy Wholesale Commodities’ forward physical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Entergy Wholesale Commodities to deliver MWh of energy, make capacity available, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The contracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2012.
Entergy Wholesale Commodities Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
Entergy Wholesale Commodities Non-Nuclear Portfolio
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
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Management's Financial Discussion and Analysis
| (a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy’s outstanding guarantees of availability provide for dollar limits on Entergy’s maximum liability under such guarantees. |
| (d) | Transaction that requires receipt or delivery of energy at a specified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the other party as specified in the contract, a portion of which may be capped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in process for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which do not operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy estimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and would have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, the Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
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Management's Financial Discussion and Analysis
million. The annual payment for each year’s output is due by January 15 of the following year. Entergy will record the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2012, 2011, and 2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2012, based on power prices at that time, Entergy had liquidity exposure of $203 million under the guarantees in place supporting Entergy Wholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $7 million of posted cash collateral to the ISOs. As of December 31, 2012, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $106 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2012, Entergy would have been required to provide approximately $48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 2016 have public investment grade credit ratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
National Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address some of the issues that NEPA requires the NRC to address before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a revised Waste Confidence Decision within 24 months.
Critical Accounting Estimates
The preparation of Entergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in these assumptions and measurements could produce estimates that would have a material effect on the presentation of Entergy’s financial position, results of operations, or cash flows.
Nuclear Decommissioning Costs
Entergy subsidiaries own nuclear generation facilities in both the Utility and Entergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates.
| · | Cost Escalation Factors - Entergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by factors ranging from approximately 2.0% to 3.25%. A 50 basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 10% to 18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant’s retirement must be estimated. A high probability that the plant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a SAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset’s remaining economic life. |
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Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop a repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2011, Entergy Wholesale Commodities recorded a reduction of $34.1 million in its decommissioning cost liability for a plant as a result of a revised decommissioning cost study obtained to comply with a state regulatory requirement. The revised cost study resulted in a change in the undiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the amount of undepreciated assets.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
explained
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. Entergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Entergy evaluates unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income in 2012, 2011, and 2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds. Additional impairments could be recorded in 2013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate for the Utility and Entergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; |
| · | Rate of increase in future compensation levels; |
Entergy reviews the first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and volatility in the financial equity markets have impacted Entergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy’s projected stream of benefit payments. Based on recent market trends, the discount rates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from 4.31% to 4.50% for its specific pension plans (4.36% combined rate for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was 4.36%. The discount rate used to calculate its 2011 other postretirement benefit obligation and 2012 postretirement benefit cost was 5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2012 accumulated postretirement benefit obligation and 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in future compensation levels used to calculate 2012 and 2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy’s non-taxable postretirement benefit assets are 65% equity securities and 35% fixed-income securities and, for its taxable other postretirement benefit assets, 65% equity securities and 35% fixed-income securities. This takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate other postretirement costs was 8.5% for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2012, Entergy’s total qualified pension cost was $264 million. Entergy anticipates 2013 qualified pension cost to be $332 million. Pension funding was approximately $170.5 million for 2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $163.3 million in 2013, although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
The Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in minimum funding requirements for single employer defined benefit plans in response to the current, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions to the pension trust will increase after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 2012 were $138.4 million, including $31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 2013 postretirement health care and life insurance benefit costs to be $146.8 million. This includes a projected $34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $82.2 million to its postretirement plans in 2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $82.5 million in 2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state utility operations, Entergy is subject to a number of federal and state laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to air emissions, water discharges, solid and hazardous waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to comply or address any impacts to the environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions.
| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA or relevant state or local authority. |
Litigation
Entergy is regularly named as a defendant in a number of lawsuits involving employment, customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, the ultimate outcome of the litigation to which Entergy is exposed has the potential to materially affect the results of operations of Entergy or Registrant Subsidiaries.
Uncertain Tax Positions
Entergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any provisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities.
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
Management of Entergy Corporation and its subsidiaries has prepared and is responsible for the financial statements and related financial information included in this document. To meet this responsibility, management establishes and maintains a system of internal controls over financial reporting designed to provide reasonable assurance regarding the preparation and fair presentation of financial statements in accordance with generally accepted accounting principles. This system includes communication through written policies and procedures, an employee Code of Entegrity, and an organizational structure that provides for appropriate division of responsibility and training of personnel. This system is also tested by a comprehensive internal audit program.
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2012, which is included herein on pages 416 through 423.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2012. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation |
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc. |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
ALYSON M. MOUNT Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. | WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc. |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,302,079 | | | $ | 11,229,073 | | | $ | 11,487,577 | | | $ | 10,745,650 | | | $ | 13,093,756 | |
| Income from continuing operations | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | | | $ | 1,251,050 | | | $ | 1,240,535 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | | | $ | 6.39 | | | $ | 6.39 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | | | $ | 6.30 | | | $ | 6.20 | |
| Dividends declared per share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | | | $ | 3.00 | | | $ | 3.00 | |
| Return on common equity | | | 9.33 | % | | | 15.43 | % | | | 14.61 | % | | | 14.85 | % | | | 15.42 | % |
| Book value per share, year-end | | $ | 51.72 | | | $ | 50.81 | | | $ | 47.53 | | | $ | 45.54 | | | $ | 42.07 | |
| Total assets | | $ | 43,202,502 | | | $ | 40,701,699 | | | $ | 38,685,276 | | | $ | 37,561,953 | | | $ | 36,616,818 | |
| Long-term obligations (1) | | $ | 12,141,370 | | | $ | 10,268,645 | | | $ | 11,575,973 | | | $ | 11,277,314 | | | $ | 11,734,411 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 3,022 | | | $ | 3,369 | | | $ | 3,375 | | | $ | 2,999 | | | $ | 3,610 | |
| Commercial | | | 2,174 | | | | 2,333 | | | | 2,317 | | | | 2,184 | | | | 2,735 | |
| Industrial | | | 2,034 | | | | 2,307 | | | | 2,207 | | | | 1,997 | | | | 2,933 | |
| Governmental | | | 198 | | | | 205 | | | | 212 | | | | 204 | | | | 248 | |
| Total retail | | | 7,428 | | | | 8,214 | | | | 8,111 | | | | 7,384 | | | | 9,526 | |
| Sales for resale | | | 179 | | | | 216 | | | | 389 | | | | 206 | | | | 325 | |
| Other | | | 264 | | | | 244 | | | | 241 | | | | 290 | | | | 222 | |
| Total | | $ | 7,871 | | | $ | 8,674 | | | $ | 8,741 | | | $ | 7,880 | | | $ | 10,073 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 34,664 | | | | 36,684 | | | | 37,465 | | | | 33,626 | | | | 33,047 | |
| Commercial | | | 28,724 | | | | 28,720 | | | | 28,831 | | | | 27,476 | | | | 27,340 | |
| Industrial | | | 41,181 | | | | 40,810 | | | | 38,751 | | | | 35,638 | | | | 37,843 | |
| Governmental | | | 2,435 | | | | 2,474 | | | | 2,463 | | | | 2,408 | | | | 2,379 | |
| Total retail | | | 107,004 | | | | 108,688 | | | | 107,510 | | | | 99,148 | | | | 100,609 | |
| Sales for resale | | | 3,200 | | | | 4,111 | | | | 4,372 | | | | 4,862 | | | | 5,401 | |
| Total | | | 110,204 | | | | 112,799 | | | | 111,882 | | | | 104,010 | | | | 106,010 | |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,326 | | | $ | 2,414 | | | $ | 2,566 | | | $ | 2,711 | | | $ | 2,794 | |
| Billed Electric Energy Sales (GWh) | | | 46,178 | | | | 43,497 | | | | 42,934 | | | | 43,743 | | | | 44,875 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of comprehensive income, consolidated statements of cash flows, and consolidated statements of changes in equity for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 27, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,870,649 | | | $ | 8,673,517 | | | $ | 8,740,637 | |
| Natural gas | | | 130,836 | | | | 165,819 | | | | 197,658 | |
| Competitive businesses | | | 2,300,594 | | | | 2,389,737 | | | | 2,549,282 | |
| TOTAL | | | 10,302,079 | | | | 11,229,073 | | | | 11,487,577 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,036,835 | | | | 2,492,714 | | | | 2,518,582 | |
| Purchased power | | | 1,255,800 | | | | 1,564,967 | | | | 1,659,416 | |
| Nuclear refueling outage expenses | | | 245,600 | | | | 255,618 | | | | 256,123 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Other operation and maintenance | | | 3,045,392 | | | | 2,867,758 | | | | 2,969,402 | |
| Decommissioning | | | 184,760 | | | | 190,595 | | | | 211,736 | |
| Taxes other than income taxes | | | 557,298 | | | | 536,026 | | | | 534,299 | |
| Depreciation and amortization | | | 1,144,585 | | | | 1,102,202 | | | | 1,069,894 | |
| Other regulatory charges - net | | | 175,104 | | | | 205,959 | | | | 44,921 | |
| TOTAL | | | 9,000,898 | | | | 9,215,839 | | | | 9,264,373 | |
| | | | | | | | | | | | | |
| Gain on sale of business | | | - | | | | - | | | | 44,173 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 1,301,181 | | | | 2,013,234 | | | | 2,267,377 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 92,759 | | | | 84,305 | | | | 59,381 | |
| Interest and investment income | | | 127,776 | | | | 128,994 | | | | 184,077 | |
| Miscellaneous - net | | | (53,214 | ) | | | (59,271 | ) | | | (48,124 | ) |
| TOTAL | | | 167,321 | | | | 154,028 | | | | 195,334 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 606,596 | | | | 551,521 | | | | 610,146 | |
| Allowance for borrowed funds used during construction | | | (37,312 | ) | | | (37,894 | ) | | | (34,979 | ) |
| TOTAL | | | 569,284 | | | | 513,627 | | | | 575,167 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 899,218 | | | | 1,653,635 | | | | 1,887,544 | |
| | | | | | | | | | | | | |
| Income taxes | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | |
| Dividends declared per common share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 177,324,813 | | | | 177,430,208 | | | | 186,010,452 | |
| Diluted average number of common shares outstanding | | | 177,737,565 | | | | 178,370,695 | | | | 187,814,235 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | | | | | | | |
| (net of tax expense (benefit) of ($55,750), $34,411, and ($7,088) | | | (97,591 | ) | | | 71,239 | | | | (11,685 | ) |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax benefit of $61,223, $131,198, and $14,387) | | | (91,157 | ) | | | (223,090 | ) | | | (8,527 | ) |
| Net unrealized investment gains | | | | | | | | | | | | |
| (net of tax expense of $61,104, $19,368, and $51,130) | | | 63,609 | | | | 21,254 | | | | 57,523 | |
| Foreign currency translation | | | | | | | | | | | | |
| (net of tax expense (benefit) of $275, $192, and ($182)) | | | 508 | | | | 357 | | | | (338 | ) |
| Other comprehensive income (loss) | | | (124,631 | ) | | | (130,240 | ) | | | 36,973 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | | 743,732 | | | | 1,237,132 | | | | 1,307,278 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| Comprehensive Income Attributable to Entergy Corporation | | $ | 722,042 | | | $ | 1,216,199 | | | $ | 1,287,215 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 1,771,649 | | | | 1,745,455 | | | | 1,705,331 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (26,479 | ) | | | (280,029 | ) | | | 718,987 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Gain on sale of business | | | - | | | | - | | | | (44,173 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (14,202 | ) | | | 28,091 | | | | (99,640 | ) |
| Fuel inventory | | | (11,604 | ) | | | 5,393 | | | | (10,665 | ) |
| Accounts payable | | | (6,779 | ) | | | (131,970 | ) | | | 216,635 | |
| Prepaid taxes and taxes accrued | | | 55,484 | | | | 580,042 | | | | (116,988 | ) |
| Interest accrued | | | 1,152 | | | | (34,172 | ) | | | 17,651 | |
| Deferred fuel costs | | | (99,987 | ) | | | (55,686 | ) | | | 8,909 | |
| Other working capital accounts | | | (151,989 | ) | | | 41,875 | | | | (160,326 | ) |
| Changes in provisions for estimated losses | | | (24,808 | ) | | | (11,086 | ) | | | 265,284 | |
| Changes in other regulatory assets | | | (398,428 | ) | | | (673,244 | ) | | | 339,408 | |
| Changes in pensions and other postretirement liabilities | | | 644,099 | | | | 962,461 | | | | (80,844 | ) |
| Other | | | (21,710 | ) | | | (415,685 | ) | | | (103,793 | ) |
| Net cash flow provided by operating activities | | | 2,940,285 | | | | 3,128,817 | | | | 3,926,081 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (2,674,650 | ) | | | (2,040,027 | ) | | | (1,974,286 | ) |
| Allowance for equity funds used during construction | | | 96,131 | | | | 86,252 | | | | 59,381 | |
| Nuclear fuel purchases | | | (557,960 | ) | | | (641,493 | ) | | | (407,711 | ) |
| Payment for purchase of plant | | | (456,356 | ) | | | (646,137 | ) | | | - | |
| Proceeds from sale of assets and businesses | | | - | | | | 6,531 | | | | 228,171 | |
| Insurance proceeds received for property damages | | | - | | | | - | | | | 7,894 | |
| Changes in securitization account | | | 4,265 | | | | (7,260 | ) | | | (29,945 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | (72,000 | ) |
| Payments to storm reserve escrow account | | | (8,957 | ) | | | (6,425 | ) | | | (296,614 | ) |
| Receipts from storm reserve escrow account | | | 27,884 | | | | - | | | | 9,925 | |
| Decrease (increase) in other investments | | | 15,175 | | | | (11,623 | ) | | | 24,956 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 109,105 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,074,055 | | | | 1,360,346 | | | | 2,606,383 | |
| Investment in nuclear decommissioning trust funds | | | (2,196,489 | ) | | | (1,475,017 | ) | | | (2,730,377 | ) |
| Net cash flow used in investing activities | | | (3,639,797 | ) | | | (3,446,853 | ) | | | (2,574,223 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | |
| Long-term debt | | | 3,478,361 | | | | 2,990,881 | | | | 3,870,694 | |
| Mandatorily redeemable preferred membership units of subsidiary | | | 51,000 | | | | - | | | | - | |
| Treasury stock | | | 62,886 | | | | 46,185 | | | | 51,163 | |
| Retirement of long-term debt | | | (3,130,233 | ) | | | (2,437,372 | ) | | | (4,178,127 | ) |
| Repurchase of common stock | | | - | | | | (234,632 | ) | | | (878,576 | ) |
| Redemption of subsidiary common and preferred stock | | | - | | | | (30,308 | ) | | | - | |
| Changes in credit borrowings and commercial paper - net | | | 687,675 | | | | (6,501 | ) | | | (8,512 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (589,209 | ) | | | (589,605 | ) | | | (603,854 | ) |
| Preferred stock | | | (22,329 | ) | | | (20,933 | ) | | | (20,063 | ) |
| Net cash flow provided by (used in) financing activities | | | 538,151 | | | | (282,285 | ) | | | (1,767,275 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (508 | ) | | | 287 | | | | 338 | |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (161,869 | ) | | | (600,034 | ) | | | (415,079 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 694,438 | | | | 1,294,472 | | | | 1,709,551 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 532,569 | | | $ | 694,438 | | | $ | 1,294,472 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 546,125 | | | $ | 532,271 | | | $ | 534,004 | |
| Income taxes | | $ | 49,214 | | | $ | (2,042 | ) | | $ | 32,144 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 112,992 | | | $ | 81,468 | |
| Temporary cash investments | | | 419,577 | | | | 612,970 | |
| Total cash and cash equivalents | | | 532,569 | | | | 694,438 | |
| Securitization recovery trust account | | | 46,040 | | | | 50,304 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 568,871 | | | | 568,558 | |
| Allowance for doubtful accounts | | | (31,956 | ) | | | (31,159 | ) |
| Other | | | 161,408 | | | | 166,186 | |
| Accrued unbilled revenues | | | 303,392 | | | | 298,283 | |
| Total accounts receivable | | | 1,001,715 | | | | 1,001,868 | |
| Deferred fuel costs | | | 150,363 | | | | 209,776 | |
| Accumulated deferred income taxes | | | 306,902 | | | | 9,856 | |
| Fuel inventory - at average cost | | | 213,831 | | | | 202,132 | |
| Materials and supplies - at average cost | | | 928,530 | | | | 894,756 | |
| Deferred nuclear refueling outage costs | | | 243,374 | | | | 231,031 | |
| System agreement cost equalization | | | 16,880 | | | | 36,800 | |
| Prepayments and other | | | 242,922 | | | | 291,742 | |
| TOTAL | | | 3,683,126 | | | | 3,622,703 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 46,738 | | | | 44,876 | |
| Decommissioning trust funds | | | 4,190,108 | | | | 3,788,031 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 256,039 | | | | 260,436 | |
| Other | | | 436,234 | | | | 416,423 | |
| TOTAL | | | 4,929,119 | | | | 4,509,766 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 41,944,567 | | | | 39,385,524 | |
| Property under capital lease | | | 935,199 | | | | 809,449 | |
| Natural gas | | | 353,492 | | | | 343,550 | |
| Construction work in progress | | | 1,365,699 | | | | 1,779,723 | |
| Nuclear fuel | | | 1,598,430 | | | | 1,546,167 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 46,197,387 | | | | 43,864,413 | |
| Less - accumulated depreciation and amortization | | | 18,898,842 | | | | 18,255,128 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 27,298,545 | | | | 25,609,285 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 742,030 | | | | 799,006 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $914,751 as of December 31, 2012 and $1,009,103 as of | | | | | | | | |
| December 31, 2011) | | | 5,025,912 | | | | 4,636,871 | |
| Deferred fuel costs | | | 172,202 | | | | 172,202 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Accumulated deferred income taxes | | | 37,748 | | | | 19,003 | |
| Other | | | 936,648 | | | | 955,691 | |
| TOTAL | | | 7,291,712 | | | | 6,959,945 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 718,516 | | | $ | 2,192,733 | |
| Notes payable and commercial paper | | | 796,002 | | | | 108,331 | |
| Accounts payable | | | 1,217,180 | | | | 1,069,096 | |
| Customer deposits | | | 359,078 | | | | 351,741 | |
| Taxes accrued | | | 333,719 | | | | 278,235 | |
| Accumulated deferred income taxes | | | 13,109 | | | | 99,929 | |
| Interest accrued | | | 184,664 | | | | 183,512 | |
| Deferred fuel costs | | | 96,439 | | | | 255,839 | |
| Obligations under capital leases | | | 3,880 | | | | 3,631 | |
| Pension and other postretirement liabilities | | | 95,900 | | | | 44,031 | |
| System agreement cost equalization | | | 25,848 | | | | 80,090 | |
| Other | | | 261,986 | | | | 283,531 | |
| TOTAL | | | 4,106,321 | | | | 4,950,699 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 8,311,756 | | | | 8,096,452 | |
| Accumulated deferred investment tax credits | | | 273,696 | | | | 284,747 | |
| Obligations under capital leases | | | 34,541 | | | | 38,421 | |
| Other regulatory liabilities | | | 898,614 | | | | 728,193 | |
| Decommissioning and asset retirement cost liabilities | | | 3,513,634 | | | | 3,296,570 | |
| Accumulated provisions | | | 362,226 | | | | 385,512 | |
| Pension and other postretirement liabilities | | | 3,725,886 | | | | 3,133,657 | |
| Long-term debt (includes securitization bonds of $973,480 as of | | | | | | | | |
| December 31, 2012 and $1,070,556 as of December 31, 2011) | | | 11,920,318 | | | | 10,043,713 | |
| Other | | | 577,910 | | | | 501,954 | |
| TOTAL | | | 29,618,581 | | | | 26,509,219 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 186,511 | | | | 186,511 | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2012 and in 2011 | | | 2,548 | | | | 2,548 | |
| Paid-in capital | | | 5,357,852 | | | | 5,360,682 | |
| Retained earnings | | | 9,704,591 | | | | 9,446,960 | |
| Accumulated other comprehensive loss | | | (293,083 | ) | | | (168,452 | ) |
| Less - treasury stock, at cost (76,945,239 shares in 2012 and | | | | | | | | |
| 78,396,988 shares in 2011) | | | 5,574,819 | | | | 5,680,468 | |
| Total common shareholders' equity | | | 9,197,089 | | | | 8,961,270 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 9,291,089 | | | | 9,055,270 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Common Shareholders’ Equity | | | | |
| | | Subsidiaries’ Preferred Stock | | | Common Stock | | | Treasury Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 94,000 | | | $ | 2,548 | | | $ | (4,727,167 | ) | | $ | 5,370,042 | | | $ | 8,043,122 | | | $ | (75,185 | ) | | $ | 8,707,360 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,063 | | | | - | | | | - | | | | - | | | | 1,250,242 | | | | - | | | | 1,270,305 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | 36,973 | | | | 36,973 | |
| Common stock repurchases | | | - | | | | - | | | | (878,576 | ) | | | - | | | | - | | | | - | | | | (878,576 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 80,932 | | | | (2,568 | ) | | | - | | | | - | | | | 78,364 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (603,963 | ) | | | - | | | | (603,963 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,063 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,063 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2010 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,524,811 | ) | | $ | 5,367,474 | | | $ | 8,689,401 | | | $ | (38,212 | ) | | $ | 8,590,400 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,933 | | | | - | | | | - | | | | - | | | | 1,346,439 | | | | - | | | | 1,367,372 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (130,240 | ) | | | (130,240 | ) |
| Common stock repurchases | | | - | | | | - | | | | (234,632 | ) | | | - | | | | - | | | | - | | | | (234,632 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 78,975 | | | | (6,792 | ) | | | - | | | | - | | | | 72,183 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (588,880 | ) | | | - | | | | (588,880 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,933 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,933 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2011 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,680,468 | ) | | $ | 5,360,682 | | | $ | 9,446,960 | | | $ | (168,452 | ) | | $ | 9,055,270 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 21,690 | | | | - | | | | - | | | | - | | | | 846,673 | | | | - | | | | 868,363 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (124,631 | ) | | | (124,631 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | $ | 105,649 | | | | (2,830 | ) | | | - | | | | - | | | | 102,819 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (589,042 | ) | | | - | | | | (589,042 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (21,690 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (21,690 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2012 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,574,819 | ) | | $ | 5,357,852 | | | $ | 9,704,591 | | | $ | (293,083 | ) | | $ | 9,291,089 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | �� | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Agreement clearly contemplatesEnergy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all intercompany transactions have been eliminated in the consolidated financial statements. Entergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously-reported amounts have been reclassified to conform to current classifications, with no effect on net income or common shareholders’ (or members’) equity.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. The Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by subsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy’s Utility operating companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Utility operating companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 9,588 | | | $ | 6,624 | | | $ | 2,964 | | | $ | - | |
Other | | | 2,878 | | | | 2,493 | | | | 385 | | | | - | |
| Transmission | | | 3,654 | | | | 3,619 | | | | 35 | | | | - | |
| Distribution | | | 6,561 | | | | 6,561 | | | | - | | | | - | |
| Other | | | 1,654 | | | | 1,416 | | | | 235 | | | | 3 | |
| Construction work in progress | | | 1,366 | | | | 973 | | | | 392 | | | | 1 | |
| Nuclear fuel | | | 1,598 | | | | 907 | | | | 691 | | | | - | |
| Property, plant, and equipment - net | | $ | 27,299 | | | $ | 22,593 | | | $ | 4,702 | | | $ | 4 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 8,635 | | | $ | 5,441 | | | $ | 3,194 | | | $ | - | |
Other | | | 2,431 | | | | 2,032 | | | | 399 | | | | - | |
| Transmission | | | 3,344 | | | | 3,309 | | | | 35 | | | | - | |
| Distribution | | | 6,157 | | | | 6,157 | | | | - | | | | - | |
| Other | | | 1,716 | | | | 1,463 | | | | 250 | | | | 3 | |
| Construction work in progress | | | 1,780 | | | | 1,420 | | | | 359 | | | | 1 | |
| Nuclear fuel | | | 1,546 | | | | 802 | | | | 744 | | | | - | |
| Property, plant, and equipment - net | | $ | 25,609 | | | $ | 20,624 | | | $ | 4,981 | | | $ | 4 | |
Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.
“Non-utility property - at cost (less accumulated depreciation)” for Entergy is reported net of accumulated depreciation of $230.4 million and $214.3 million as of December 31, 2012 and 2011, respectively.
Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2012 and 2011, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 2012 and 2011, is shown below:
2012 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,073 | | | $ | 1,428 | | | $ | 2,180 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,943 | |
Other | | | 621 | | | | 286 | | | | 680 | | | | 545 | | | | (11 | ) | | | 371 | | | | - | |
| Transmission | | | 1,034 | | | | 573 | | | | 734 | | | | 581 | | | | 27 | | | | 642 | | | | 28 | |
| Distribution | | | 1,747 | | | | 939 | | | | 1,454 | | | | 1,065 | | | | 331 | | | | 1,025 | | | | - | |
| Other | | | 115 | | | | 187 | | | | 289 | | | | 201 | | | | 182 | | | | 106 | | | | 17 | |
| Construction work in progress | | | 206 | | | | 125 | | | | 405 | | | | 63 | | | | 11 | | | | 90 | | | | 40 | |
| Nuclear fuel | | | 304 | | | | 147 | | | | 204 | | | | - | | | | - | | | | - | | | | 253 | |
| Property, plant, and equipment - net | | $ | 5,100 | | | $ | 3,685 | | | $ | 5,946 | | | $ | 2,455 | | | $ | 540 | | | $ | 2,234 | | | $ | 2,281 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,034 | | | $ | 1,458 | | | $ | 1,561 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,388 | |
Other | | | 398 | | | | 286 | | | | 679 | | | | 350 | | | | (7 | ) | | | 325 | | | | - | |
| Transmission | | | 942 | | | | 500 | | | | 706 | | | | 510 | | | | 22 | | | | 624 | | | | 5 | |
| Distribution | | | 1,700 | | | | 856 | | | | 1,304 | | | | 1,009 | | | | 298 | | | | 990 | | | | - | |
| Other | | | 173 | | | | 192 | | | | 278 | | | | 206 | | | | 186 | | | | 110 | | | | 18 | |
| Construction work in progress | | | 120 | | | | 122 | | | | 559 | | | | 105 | | | | 14 | | | | 91 | | | | 358 | |
| Nuclear fuel | | | 273 | | | | 206 | | | | 165 | | | | - | | | | - | | | | - | | | | 158 | |
| Property, plant, and equipment - net | | $ | 4,640 | | | $ | 3,620 | | | $ | 5,252 | | | $ | 2,180 | | | $ | 513 | | | $ | 2,140 | | | $ | 1,927 | |
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2012 | | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
| 2011 | | 2.6% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.2% | | 2.8% |
| 2010 | | 2.9% | | 1.8% | | 2.4% | | 2.6% | | 3.1% | | 2.3% | | 2.9% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $142 million and $136 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.8 million and $2.7 million as of December 31, 2012 and 2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $10 million and $9.8 million as of December 31, 2012 and 2011, respectively.
As of December 31, 2012, construction expenditures included in accounts payable are $56.3 million for Entergy Arkansas, $9.7 million for Entergy Gulf States Louisiana, $110.4 million for Entergy Louisiana, $4.8 million for Entergy Mississippi, $1.9 million for Entergy New Orleans, $8.6 million for Entergy Texas, and $13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2012, the subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $86 |
| | Common Facilities | | Coal | | | | 15.75% | | $33 | | $22 |
White Bluff | Units 1 and 2 | | Coal | | 1,659 | | 57.00% | | $498 | | $319 |
Ouachita (2) | Common Facilities | | Gas | | | | 66.67% | | $169 | | $142 |
Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 40.25% | | $250 | | $170 |
Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 15.92% | | $9 | | $3 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $142 | | $99 |
Ouachita (2) | Common Facilities | | Gas | | | | 33.33% | | $87 | | $73 |
| Entergy Louisiana - | | | | | | | | | | | |
| Acadia | Common Facilities | | Gas | | | | 50.00% | | $8 | | $- |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | 1,678 | | 25.00% | | $250 | | $140 |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 29.75% | | $180 | | $113 |
Roy S. Nelson | Unit 6 Common
Facilities | | Coal | | | | 11.77% | | $6 | | $2 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $107 | | $68 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,430(4) | | 90.00%(3) | | $4,557 | | $2,569 |
| | | | | | | | | | | | |
Entergy Wholesale Commodities: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $69 | | $43 |
| Independence | Common
Facilities | | Coal | | | | 7.18% | | $16 | | $9 |
| Roy S. Nelson | Unit 6 | | Coal | | 540 | | 10.9% | | $104 | | $54 |
| Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 4.31% | | $2 | | $1 |
| | | | | | | | | | | | |
| (1) | “Total Megawatt Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
| (3) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
| (4) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Earnings per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions, Except Per Share Data) | |
| | | | | | $/share | | | | | | $/share | | | | | | $/share | |
| Net income attributable to Entergy Corporation | | $ | 846.7 | | | | | | $ | 1,346.4 | | | | | | $ | 1,250.2 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Basic earnings per average common share | | | 177.3 | | | $ | 4.77 | | | | 177.4 | | | $ | 7.59 | | | | 186.0 | | | $ | 6.72 | |
| Average dilutive effect of: | | | | | | | | | | | | | | | | | | | | | | | | |
Stock options | | | 0.3 | | | | (0.01 | ) | | | 1.0 | | | | (0.04 | ) | | | 1.8 | | | | (0.06 | ) |
Other equity plans | | | 0.1 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Diluted earnings per average common shares | | | 177.7 | | | $ | 4.76 | | | | 178.4 | | | $ | 7.55 | | | | 187.8 | | | $ | 6.66 | |
The calculation of diluted earnings per share excluded 7,164,319 options outstanding at December 31, 2012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which are shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. The cost of the stock-based compensation is charged to income over the vesting period. Awards under Entergy’s plans generally vest over three years.
Accounting for the Effects of Regulation
Entergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may make salesexist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business, where specific recovery is not provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the portion of River Bend that is not rate-regulated, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of equity unless the unrealized loss is other than temporary and therefore recorded in earnings. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment is based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds.
Equity Method Investments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified to earnings in the periods when the underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy’s other derivative instruments.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their own account,fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.
Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| · | Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act; |
| · | Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and |
| · | Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states. |
In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.
In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.
In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the requirementVPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.
Impairment
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs | Range | Weighted
Average |
| | |
| Weighted average cost of capital | 7.5%-8.0% | 7.8% |
| Long-term pre-tax operating margin (cash basis) | 6.1%-7.8% | 7.2% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Preferred Stock without Sinking Fund
Accounting standards regarding non-controlling interests and the classification and measurement of redeemable securities require the classification of preferred securities between liabilities and shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company’s preferred securities may elect a majority of the respective company’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members’ equity.
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management (whose preferred holders also had protective rights until the securities were repurchased in December 2011), are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets
Other Regulatory Assets
Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 2012 and 2011:
Entergy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 422.6 | | | $ | 395.9 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 35.1 | | | | 12.4 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Gas hedging costs - recovered through fuel rates | | | 8.3 | | | | 30.3 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 2,866.3 | | | | 2,542.0 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 970.8 | | | | 996.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 155.7 | | | | 81.2 | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 95.9 | | | | 108.8 | |
| Other | | | 75.1 | | | | 44.4 | |
Total | | $ | 5,025.9 | | | $ | 4,636.9 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 210.2 | | | $ | 187.7 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 831.2 | | | | 768.3 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.3 | | | | 4.6 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 115.2 | | | | 114.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 31.5 | | | | 34.7 | |
| Other | | | 6.2 | | | | 4.0 | |
Entergy Arkansas Total | | $ | 1,221.6 | | | $ | 1,126.9 | |
Entergy Gulf States Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 6.1 | | | $ | 12.8 | |
Gas hedging costs - recovered through fuel rates | | | 2.6 | | | | 8.6 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 300.5 | | | | 231.3 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 18.9 | | | | 10.2 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.9 | | | | 11.6 | |
| Other | | | 13.1 | | | | 4.1 | |
Entergy Gulf States Louisiana Total | | $ | 409.7 | | | $ | 333.9 | |
Entergy Louisiana
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 136.9 | | | $ | 125.8 | |
Gas hedging costs - recovered through fuel rates | | | 3.4 | | | | 12.4 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 475.6 | | | | 427.9 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 74.5 | | | | 9.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 17.6 | | | | 20.0 | |
| Other | | | 28.0 | | | | 20.3 | |
Entergy Louisiana Total | | $ | 913.6 | | | $ | 814.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 5.6 | | | $ | 5.3 | |
Gas hedging costs - recovered through fuel rates | | | 2.2 | | | | 7.8 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 57.4 | | | | 48.5 | |
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 17.8 | | | | 7.8 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 234.6 | | | | 221.1 | |
Provision for storm damages - recovered through retail rates | | | 9.2 | | | | 30.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.6 | | | | 10.7 | |
| Other | | | 8.3 | | | | 4.7 | |
Entergy Mississippi Total | | $ | 401.5 | | | $ | 393.4 | |
Entergy New Orleans
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 3.6 | | | $ | 3.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 29.9 | | | | 16.3 | |
Gas hedging costs - recovered through fuel rates | | | - | | | | 1.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 134.6 | | | | 127.6 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 15.1 | | | | 8.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 2.3 | | | | 2.6 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
| Other | | | 5.5 | | | | 5.9 | |
Entergy New Orleans Total | | $ | 202.0 | | | $ | 178.8 | |
Entergy Texas
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 1.2 | | | $ | 1.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 11.5 | | | | 4.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 258.8 | | | | 244.9 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | 737.9 | | | | 822.5 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 9.4 | | | | 10.8 | |
| Other | | | 13.6 | | | | 4.9 | |
Entergy Texas Total | | $ | 1,114.5 | | | $ | 1,178.1 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 58.9 | | | $ | 59.6 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 56.8 | | | | 11.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b) | | | 198.2 | | | | 197.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 15.6 | | | | 18.2 | |
| Other | | | 0.6 | | | | 0.6 | |
System Energy Total | | $ | 330.1 | | | $ | 287.8 | |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing occurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
| (b) | Does not earn a return on investment, but is offset by related liabilities. |
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Correction of Regulatory Asset for Income Taxes
In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and would not be recovered in the future.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a cumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.
The effect was also immaterial to the balance sheets, results of operations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Income Statement | | | | | | | | | | | | |
| Income taxes | | $ | 88,313 | | | $ | 89,736 | | | $ | 75,878 | | | $ | 92,297 | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Earnings applicable to common equity | | $ | 202,202 | | | $ | 200,779 | | | $ | 189,911 | | | $ | 173,492 | |
| | | | | | | | | | | | | | | | | |
| Statement of Cash Flows | | | | | | | | | | | | | | | | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | $ | (6,268 | ) | | $ | (4,845 | ) | | $ | 87,920 | | | $ | 104,339 | |
Changes in other regulatory assets | | $ | (80,027 | ) | | $ | (77,713 | ) | | $ | 114,528 | | | $ | 141,216 | |
Other operating activities | | $ | (35,248 | ) | | $ | (37,562 | ) | | $ | 30,717 | | | $ | 4,029 | |
| | | December 31, 2011 | |
| | | As previously reported | | | As corrected | |
| | | | | | | |
| Balance Sheet | | | | | | |
| Regulatory asset for income taxes - net | | $ | 249,058 | | | $ | 173,724 | |
Accumulated deferred income taxes - current | | $ | 5,427 | | | $ | 5,107 | |
Accumulated deferred income taxes and taxes accrued | | $ | 1,397,230 | | | $ | 1,368,563 | |
| Member’s equity | | $ | 1,439,733 | | | $ | 1,393,386 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Years Ended December 31, 2011 and 2010 | |
| | | Member’s Equity | | | Total Equity | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Statement of Changes in Equity | | | | | | |
| Balance at December 31, 2009 | | $ | 1,473,930 | | | $ | 1,445,425 | | | $ | 1,441,759 | | | $ | 1,413,254 | |
| 2010 Net income | | $ | 190,738 | | | $ | 174,319 | | | $ | 190,738 | | | $ | 174,319 | |
| Balance at December 31, 2010 | | $ | 1,539,517 | | | $ | 1,494,593 | | | $ | 1,509,213 | | | $ | 1,464,289 | |
| 2011 Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 203,027 | | | $ | 201,604 | |
| Balance at December 31, 2011 | | $ | 1,439,733 | | | $ | 1,393,386 | | | $ | 1,380,123 | | | $ | 1,333,776 | |
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 2012 and 2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
| | | | | | | |
| Entergy Arkansas | | $ | 97.3 | | | $ | 209.8 | |
| Entergy Gulf States Louisiana (a) | | $ | 99.2 | | | $ | 2.9 | |
| Entergy Louisiana (a) | | $ | 94.6 | | | $ | 1.5 | |
| Entergy Mississippi | | $ | 26.5 | | | $ | (15.8 | ) |
| Entergy New Orleans (a) | | $ | 1.9 | | | $ | (7.5 | ) |
| Entergy Texas | | $ | (93.3 | ) | | $ | (64.7 | ) |
| (a) | 2012 and 2011 include $100.1 million for Entergy Gulf States Louisiana, $68 million for Entergy Louisiana, and $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, which do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy costs for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2005 the APSC initiated an investigation into Entergy Arkansas's interim energy cost recovery rate. The investigation focused on Entergy Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC’s January 2007 order in light of the arguments advanced in Entergy Arkansas’s rehearing petition and because the value for Entergy Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas’s rehearing request and the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties did. In February 2010 the APSC denied Entergy Arkansas’s request for rehearing, and held a hearing in September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concluded with testimony through September 2010. Testimony has been filed, and the APSC will decide the case based on the record in the proceeding, including the prefiled testimony.
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the billing month based upon the level of such costs incurred two months prior to the billing month. Entergy Gulf States Louisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule has not yet been established. Entergy Louisiana has recorded provisions for the estimated outcome of this proceeding.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted annually to reflect accumulated over- or under-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The complaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. In December 2008 the defendant Entergy companies removed the attorney general’s suit to U.S. District Court in Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy companies answered the complaint and filed a counterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Entergy New Orleans
Entergy New Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges.
Entergy New Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the load (or load shape)electric fuel adjustment clause, including carrying charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, not recovered in base rates. Semi-annual revisions of the fixed fuel factor are made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund was made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the PUCT a request to refund approximately $66 million, including interest, of fuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2009 Base Rate Filing
In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating company. The response further explains thatcompanies historically have engaged in the FERC already has determined that Entergy Arkansas' short-term wholesale sales did not triggercoordinated planning, construction, and operation of generating and bulk transmission facilities under the "right-of-first-refusal" provisionterms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. While
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit recently determinedissued its decision in April 2008. The D.C. Circuit concluded that the "right-of-first-refusal" issueFERC’s orders had failed to adequately explain both its conclusion that it was not properly beforeprohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC at the time of its earlier decisionfor further proceedings on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion. On December 7, 2009,these issues.
In October 2011, the FERC issued an order settingaddressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were unsuccessfulterminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the matter isfiling, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in August 2010.March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Independent Coordinator of Transmission
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of independent RTOs (regional transmission organizations). Delays in implementing the FERC RTO order occurred due to a variety of reasons, including the fact that utility companies, other stakeholders, and federal and state regulators have had to work to resolve various issues related to the establishment of such RTOs.
In November 2006, after nearly a decade of effort, including filings, orders, technical conferences, and proceedings at the FERC, the Utility operating companies installed the Southwest Power Pool (SPP), an RTO, as their Independent Coordinator of Transmission (ICT). The ICT structure approved by FERC is not an RTO under FERC Order No. 2000 and installation doesof the ICT did not transfer control of Entergy'sthe Entergy transmission system to the ICT, but rather vests withICT. Instead, the ICT performs some, but not all, of the functions performed by a typical RTO, as well as certain functions unique to the Entergy transmission system. In particular, the ICT was vested with responsibility for:
| · | granting or denying transmission service on the Utility operating companies'companies’ transmission system. |
| · | administering the Utility operating companies'companies’ OASIS node for purposes of processing and evaluating transmission service requests and ensuring compliance with the Utility operating companies' obligation to post transmission-related information.requests. |
| · | developing a base plan for the Utility operating companies'companies’ transmission system that will result in the ICT making the determination onand deciding whether costs of transmission upgrades should be rolled into the Utility operating companies'companies’ transmission rates or directly assigned to the customer requesting or causing an upgrade to be constructed. This should result in a transmission pricing structure that ensures that the Utility operating companies' retail native load customers are required to pay for only those upgrades necessary to reliably serve their needs. |
| · | serving as the reliability coordinator for the Entergy transmission system. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | overseeing the operation of the weekly procurement process (WPP). |
| · | evaluating interconnection-related investments already made on the Entergy System for purposes of determining the future allocation of the uncredited portion of these investments, pursuant to a detailed methodology. The ICT agreement also clarifies the rights that customers receive when they fund a supplemental upgrade. |
The initial term of the ICT is four years, and Entergy is precluded from terminating the ICT prior to the end of the four-year period.
After the FERC issued its April 2006 order approving the ICT proposal, the Utility operating companies made a series of compliance filings with the FERC that were protested by various parties. The FERC accepted the compliance filings and denied various requests for rehearing. As stated above, SPP was installed as the ICT in November 2006.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In October 2006 the Utility operating companies filed revisions to their Open Access Transmission Tariff (OATT) with the FERC to establish a mechanism to recover from their wholesale transmission customers the (1) costs incurred to develop or join an RTO and to develop the ICT; and (2) on-going costs that will be incurred under the ICT agreement. Several parties intervened opposing the proposed tariff revisions. In December 2006 the FERC accepted for filing Entergy's proposed tariff revisions, and set them for hearing and settlement procedures. In its Order, the FERC concluded that each of the Utility operating companies "should be allowed the opportunity to recover its start up costs associated with its formation of the ICT and its participation in prior failed attempts to form an RTO," and also that the proposed tariffs raised issues of fact that are more properly addressed through hearing and settlement procedures. In June 2007 the Utility operating companies reached a settlement-in-principle with the parties to the proceeding and the FERC approved the settlement in November 2007.
In the FERC's April 2006 order that approved Entergy's ICT proposal, the FERC stated that the WPP must be operational within approximately 14 months of the FERC order, or June 24, 2007, or the FERC may reevaluate all approvals to proceed with the ICT. The Utility operating companies filed status reports with the FERC notifying the FERC that, due to unexpected issues with the development of the WPP software and testing, the WPP was still not operational. The Utility operating companies also filed various tariff revisions with the FERC in 2007 and 2008 to address issues identified during the testing of the WPP and changes to the effective date of the WPP. On October 10, 2008, the FERC issued an order accepting a tariff amendment establishing that the WPP shall take effect at a date to be determined, after completion of successful simulation trials and the ICT's endorsement of the WPP's implementation. On January 16, 2009, the Utility operating companies filed a compliance filing with the FERC that included the ICT's endorsement of the WPP implementation, subject to the FERC's acceptance of certain additional tariff amendments and the completion of simulation testing and certain other items. The Utility operating companies filed the tariff amendments supported by the ICT on the same day. The amendments proposed to further amend the WPP to (a) limit supplier offers in the WPP to on-peak periods and (b) eliminate the granting of certain transmission service through the WPP.
On March 17, 2009, the FERC issued an order conditionally approving the proposed modification to the WPP to allow the process to be implemented the week of March 23, 2009. In its order approving the requested modifications, the FERC imposed additional conditions related to the ICT arrangement and indicated it was going to evaluate the success of the ICT arrangement, including the cost and benefits of implementing the WPP and whether the WPP goes far enough to address the transmission access issues that the ICT and WPP were intended to address. The FERC, in conjunction with the APSC, the LPSC, the MPSC, the PUCT, and the City Council, hosted a conference on June 24, 2009, to discuss the ICT arrangement and transmission access on the Entergy transmission system. In compliance with the FERC's March 2009 order, in November 2009 the Utility operating companies filed with the FERC a process for evaluating the modification or replacement of the current ICT and WPP arrangements.
During the conference, several issues were raised by regulators and market participants, including the adequacy of the Utility operating companies'companies’ capital investment in the transmission system, the Utility operating companies'companies’ compliance with the existing North American Electric Reliability Corporation (NERC) reliability planning standards, the availability of transmission service across the system, and whether the Utility operating companies could have purchased lower cost power from merchant generators located on the transmission system rather than running their older generating facilities. On July 20, 2009, the Utility operating companies filed comments with the FERC responding to the issues raised during the conference. The comments explainexplained that: 1) the Utility operating companies believe that the ICT arrangement has fulfilled its objectives; 2) the Utility operating companies'companies’ transmission planning practices comply with laws and regulations regarding the planning and operation of the transmission system; and 3) these planning practices have resulted in a system that meets applicable reliability standards and is sufficiently robust to allow the Utility operating companies both to substantially increase the amount of transmission service available to third parties and to make significant amounts of economic purchases from the wholesale market for the benefit of the Utility operating companies'companies’ retail customers. The Utility operating companies also explainexplained that, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies’ transmission system that
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service. Additionally, the Utility operating companies commitcommitted in their response to exploring and working on potential reforms or alternatives for the ICT arrangement that could take effect following the initial term.arrangement. The Utility operating companies'companies’ comments also recognizerecognized that NERC iswas in the process of amending certain of its transmission reliability planning standards and that the amended standards, if approved by the FERC, will result in more stringent transmission planning criteria being applicable in the future. The FERC may also make other changes to transmission reliability standards. These changesChanges to the reliability standards wouldcould result in increased capital expenditures by the Utility operating companies.
TheIn 2009 the Entergy Regional State Committee (E-RSC), which is comprised of representatives from all of the Utility operating companies' retail regulators, has beenwas formed to consider several of these issues related to the ICT and Entergy's transmission system. Among other things, the E-RSC in concert with the FERC plan to conductconducted a cost/benefitsbenefit analysis comparing the ICT arrangement and a proposal under which Entergy would join the SPPto other transmission proposals, including participation in an RTO.
In November 2010 the FERC Auditsissued an order accepting the Utility operating companies’ proposal to extend the ICT arrangement with SPP until November 2012. In addition, in December 2010 the FERC issued an order that granted the E-RSC additional authority over transmission upgrades and cost allocation. In July 2012 the LPSC approved, subject to conditions, Entergy Gulf States Louisiana’s and Entergy Louisiana’s request to extend the ICT arrangement and to transition to MISO as the provider of ICT services effective as of November 2012 and continuing until the Utility operating companies join the MISO RTO, or December 31, 2013, whichever occurs first. In January 2013 the LPSC approved the use of a market monitor as part of the ICT services to be provided by MISO.
In October 2012 the FERC accepted the Utility operating companies’ proposal for (a) an interim extension of the ICT arrangement through and until the earlier of December 31, 2014 or the date the proposed transfer of functional control of the Utility operating companies’ transmission assets to the MISO RTO is completed and (b) the transfer from SPP to MISO as the provider of ICT services, effective December 1, 2012. In December 2012 the FERC issued an order accepting further revisions to the Utility operating companies’ OATT, including a Monitoring Plan and Retention Agreement, to establish Potomac Economics Ltd., MISO’s current market monitor, as an independent Transmission Service Monitor for the Entergy transmission system, effective as of December 1, 2012. Potomac will monitor actions of Entergy and transmission customers within the Entergy region as related to systems operations, reliability coordination, transmission planning, and transmission reservations and scheduling.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
System Agreement
The FERC regulates wholesale rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement. The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement. See Note 2 to the financial statements for discussions of this litigation.
Utility Operating Company Notices of Termination of System Agreement Participation
Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In October 2007 the MPSC issued a letter confirming its belief that Entergy Mississippi should exit the System Agreement in light of the recent developments involving the System Agreement. In November 2007, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC.
In February 2009, Entergy Arkansas and Entergy Mississippi filed with the FERC their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. While the FERC had indicated previously that the notices should be filed 18 months prior to Entergy Arkansas’s termination (approximately mid-2012), the filing explains that resolving this issue now, rather than later, is important to ensure that informed long-term resource planning decisions can be made during the years leading up to Entergy Arkansas’s withdrawal and that all of the Utility operating companies are properly positioned to continue to operate reliably following Entergy Arkansas’s and, eventually, Entergy Mississippi’s, departure from the System Agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96-month notice period without payment of a fee or the requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. In February 2011, the FERC denied the LPSC’s and the City Council’s rehearing requests. In September and October 2012, the U.S. Court of Appeals for the D.C. Circuit denied the LPSC’s and the City Council’s appeals of the FERC decisions. In January 2013, the LPSC and the City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
In November 2012 the Utility operating companies filed amendments to the System Agreement with the FERC pursuant to section 205 of the Federal Power Act. The amendments consist primarily of the technical revisions needed to the System Agreement to (i) allocate certain charges and credits from the MISO settlement statements to the participating Utility operating companies; and (ii) address Entergy Arkansas’s withdrawal from the System Agreement. As noted in the filing, the Utility operating companies’ plan to integrate into MISO and the revisions to the System Agreement are the main feature of the Utility operating companies’ future operating arrangements, including the successor arrangements with respect to the departure of Entergy Arkansas
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
from the System Agreement. Additional aspects of the Utility operating companies’ future operating arrangements will be addressed in other FERC dockets related to the allocation of the Ouachita plant transmission upgrade costs and the upcoming filings at the FERC related to the rates, terms, and conditions under which the Utility operating companies will join MISO. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments filed in November 2012 and other aspects of the Utility operating companies’ future operating arrangements, including requests that the continued viability of the System Agreement in MISO (among other issues) be set for hearing by the FERC.
See also the discussion of the order of the PUCT concerning Entergy Texas’s proposal to join MISO discussed further in the “Federal Regulation – Entergy’s Proposal to Join MISO” section below.
Entergy’s Proposal to Join MISO
On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining MISO, which is expected to provide long-term benefits for the customers of each of the Utility operating companies. MISO is an RTO that operates in eleven U.S. states (Illinois, Indiana, Iowa, Kentucky, Michigan, Minnesota, Missouri, Montana, North Dakota, South Dakota, and Wisconsin) and also in Canada. Each of the Utility operating companies filed an application with its retail regulator concerning the proposal to join MISO and transfer control of each company’s transmission assets to MISO. The applications to join MISO sought a finding that membership in MISO is in the public interest. Becoming a member of MISO will not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. Once the Utility operating companies are fully integrated as members, however, MISO will assume control of transmission planning and congestion management and, through its Day 2 market, MISO will provide schedules and pricing for the commitment and dispatch of generation that is offered into MISO’s markets, as well as pricing for load that bids into the market.
The DivisionLPSC voted to grant Entergy Gulf States Louisiana’s and Entergy Louisiana’s application for transfer of Auditscontrol to MISO, subject to conditions, in May 2012 and issued its order in June 2012.
On October 26, 2012, the APSC authorized Entergy Arkansas to sign the MISO Transmission Owners Agreement, which Entergy Arkansas has now done, and move forward with the MISO integration process. The APSC stated in its order that it would give conditional approval of Entergy Arkansas’s application upon MISO’s filing with the APSC proof of approval by the appropriate MISO entities of certain governance enhancements. On October 31, 2012, MISO filed with the APSC proof of approval of the governance enhancements and requested a finding of compliance and approval of Entergy Arkansas's application. On November 21, 2012, the APSC issued an order requiring that MISO file a “higher level of proof” that the MISO Transmission Owners have “officially approved and adopted” one of the proposed governance enhancements in the Officeform of Enforcementsworn compliance testimony, or a sworn affidavit, from the chairman of the MISO Transmission Owners Committee. On January 7, 2013, MISO filed its Motion for Finding of Compliance with the APSC’s order, with supporting testimony, including a copy of the testimony of the Chairman of the MISO Transmission Owners Committee in support of a filing at the FERC made January 4, 2013, on behalf of MISO and a majority of its transmission owners, jointly submitting changes to Appendix K of the MISO Transmission Owner Agreement to implement the governance enhancements. MISO stated that the evidence submitted to the APSC showed that a majority of the MISO Transmission Owners have adopted and approved the MISO governance enhancements and the Division of Compliancejoint filing submitted to FERC on January 4, 2013, and asked that the APSC find MISO in the Office of Reliability of the FERC jointly commenced an audit of Entergy Services, Inc. on October 1, 2009. The audit will evaluate Entergy Services': (1) practices related to Bulk Electric System planning and operations; (2) compliance with the requirements contained withinconditions of the APSC’s October 26, 2012 order, and that the APSC expeditiously enter an order approving Entergy Arkansas’s application to join MISO.
On January 23, 2013, Entergy Arkansas filed a Motion to Discontinue Activities Necessary to Operate as a True Stand-Alone Electric Utility, with supporting testimony, in which Entergy Arkansas requested an order from the APSC authorizing it to drop the stand-alone option by March 1, 2013. Consistent with the conditions enumerated in a previous APSC order, Entergy Arkansas’s testimony stated that there is a low risk that MISO’s integration of Entergy Arkansas will not be successfully completed on time.
In September 2012, Entergy Mississippi and the Mississippi Public Utilities Staff filed a joint stipulation indicating that they agree that Entergy Mississippi’s proposed transfer of functional control of its Open Access Transmission Tariff;transmission facilities to MISO is in the public interest, subject to certain contingencies and (3) other obligationsconditions. In November 2012 the MPSC issued an order approving a joint stipulation filed by Entergy Mississippi and responsibilitiesthe Mississippi Public Utilities Staff, concluding that Entergy Mississippi’s proposed transfer of functional control of its transmission facilities is in the public interest, subject to certain conditions.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In November 2012 the City Council issued a resolution concerning the application of Entergy New Orleans. In its resolution, the City Council approved a settlement agreement agreed to by Entergy New Orleans, Entergy Louisiana, MISO, and the advisors to the City Council related to joining MISO and found that it is in the public interest for Entergy New Orleans and Entergy Louisiana to join MISO, subject to certain conditions.
Entergy Texas submitted its change of control filing in April 2012. In August 2012 parties in the PUCT proceeding, with the exception of Southwest Power Pool, filed a non-unanimous settlement. The substance of the settlement is that it is in the public interest for Entergy Texas to transfer operational control of its transmission facilities to MISO under certain conditions. In October 2012 the PUCT issued an order approving the transfer as approvedin the public interest, subject to the terms and conditions in the settlement, with several additional terms and conditions requested by the FERC. The audit will coverPUCT and agreed to by the period from April 1, 2006settling parties. In particular, the settlement and the PUCT order require Entergy Texas, unless otherwise directed by the PUCT, to provide by October 31, 2013 its notice to exit the System Agreement, subject to certain conditions. In addition, the PUCT order requires Entergy Texas, as well as Entergy Corporation and Entergy Services, Inc., to exercise reasonable best efforts to engage the Utility operating companies and their retail regulators in searching for a consensual means, subject to FERC approval, of allowing Entergy Texas to exit the System Agreement prior to the present. end of the mandatory 96-month notice period.
With these actions on the applications, the Utility operating companies have obtained from all of the retail regulators the public interest findings sought by the Utility operating companies in order to move forward with their plan to join MISO. Each of the retail regulators’ orders includes conditions, some of which entail compliance prospectively.
In December 2012 the PUCT Staff filed a memo in the proceeding established by the PUCT to track compliance with its October 2012 order. In the memo, the PUCT Staff expressed concerns about the effect of Entergy Texas’s exit from the System Agreement on power purchase agreements for gas and oil-fired generation units owned by Entergy Texas and Entergy Gulf States Louisiana that were entered into upon the December 2007 jurisdictional separation of Entergy Gulf States, Inc. and, further, expressed concerns about the implications of these issues as they relate to the continuing validity of the PUCT’s October 2012 order regarding MISO. Entergy Texas subsequently filed a position statement relating that Entergy Texas’s exit from the System Agreement would trigger the termination of the power purchase agreements of concern to the PUCT Staff. Entergy Texas expressed its continuing commitment to work collaboratively with the PUCT Staff and other parties to address ongoing issues and challenges in implementing the PUCT order including any potential impact from termination of the power purchase agreements. In January 2013, Entergy Texas filed an updated analysis of the effect of termination of the power purchase agreements indicating that termination would have little or no effect on Entergy Texas’s costs. An independent consultant has been retained to assist the PUCT Staff in its assessment of the analysis.
The Energy Policy ActFERC filings related to the terms and conditions of 2005 providesintegrating the Utility operating companies into MISO are planned to be made by mid-2013. The target implementation date for joining MISO is December 2013. Entergy believes that the decision to join MISO should be evaluated separately from and independent of the decision regarding the proposed transaction with ITC, and Entergy plans to continue to pursue the MISO proposal and the planned spin-off or split-off exchange offer and merger of Entergy’s Transmission Business with ITC on parallel regulatory paths.
In addition to the FERC filings planned to be made by mid-2013, there are a number of proceedings pending at FERC related to the Utility operating companies’ proposal to join MISO. In April 2012 the FERC conditionally accepted MISO’s proposal related to the allocation of transmission upgrade costs in connection with the transition and integration of the Utility operating companies into MISO. In November 2012 the FERC issued an order denying the requests for rehearing of the April 2012 order, and conditionally accepting MISO’s May 2012 compliance filing, subject to a further compliance filing due within 30 days of the date of the November 2012 Order. In December 2012, MISO and the MISO Transmission Owners submitted to FERC a request for rehearing and proposed revisions to the MISO Tariff in compliance with FERC’s November 2012 order. The request for rehearing and compliance filing are pending at FERC.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In addition, the Utility operating companies have proposed giving authority to impose civil penaltiesthe E-RSC, upon unanimous vote and within the first five years after the Utility operating companies join the MISO RTO, (i) to require the Utility operating companies to file with the FERC a proposed allocation of certain transmission upgrade costs among the Utility operating companies’ transmission pricing zones that would differ from the allocation that would occur under the MISO OATT and (ii) to direct the Utility operating companies as transmission owners to add projects to MISO’s transmission expansion plan. On January 4, 2013, MISO submitted a filing with the FERC to give the Organization of MISO States, Inc. enhanced authority for violationsdetermining transmission cost allocation methodologies to be filed pursuant to section 205 of the Federal Power Act.
On January 17, 2013, Occidental Chemical Corporation filed a complaint against MISO and a petition for declaratory judgment, both with the FERC, alleging that MISO’s proposed treatment of Qualifying Facilities (QFs) in the Entergy region is unduly discriminatory in violation of sections 205 and 206 of the Federal Power Act and violates PURPA and the FERC’s implementing regulations. Occidental’s filing asks that the FERC declare that MISO’s QF integration plan is unlawful, find that the plan cannot be implemented because MISO did not file it pursuant to section 205 of the Federal Power Act, and direct that MISO modify certain aspects of the plan. On February 14, 2013, Entergy sought to intervene and filed an answer to these pleadings. On January 22, 2013, the MPSC, APSC, and City Council filed a petition for declaratory order with the FERC requesting that the FERC determine whether the avoided cost calculation methodology proposed in an LPSC proceeding by Entergy Services, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, complies with PURPA and the FERC’s implementing regulations. On February 21, 2013, Entergy Services intervened and filed an answer to the petition for declaratory order.
SERC Reliability CorporationEntergy’s initial filings with its retail regulators estimated that the transition and implementation costs of joining the MISO RTO could be up to $105 million if all of the Utility operating companies join the MISO RTO, most of which will be spent in late 2012 and 2013. Maintaining the viability of the alternatives of Entergy Arkansas joining the MISO RTO alone or standing alone within an ICT arrangement is expected to result in an additional cost of approximately $35 million, for a total estimated cost of up to $140 million. This amount could increase with extended litigation in various regulatory proceedings. It is expected that costs will be incurred to obtain regulatory approvals, to revise or implement commercial and legal agreements, to integrate transmission and generation facilities, to develop back-office accounting and settlement systems, and to build out communications infrastructure.
FERC Reliability Standards Investigation
Entergy has notified the SERC Reliability Corporation (SERC)FERC’s Division of potential violationsInvestigations is conducting an investigation of certain FERCissues relating to the Utility operating companies compliance with certain reliability standards includingrelated to protective system maintenance, facility ratings and modeling, training, and communications. In November 2012 the FERC issued a
“Staff Notice of Alleged Violations” stating that the Division of Investigations’ staff has preliminarily determined that Entergy Services violated thirty-three requirements of sixteen reliability standards by failing to adequately perform certain Critical Infrastructure Protection standards.functions. Entergy Services is working within the SERCprocess of responding to provide information concerning these potential violations.the staff’s concerns. The Energy Policy Act of 2005 provides authority to impose civil penalties for violations of the Federal Power Act and FERC regulations.
U.S. Department of Justice Investigation
In September 2010, Entergy was notified that the U.S. Department of Justice had commenced a civil investigation of competitive issues concerning certain generation procurement, dispatch, and transmission system practices and policies of the Utility operating companies. In November 2012 the U.S. Department of Justice issued a press release in which the U.S. Department of Justice stated, among other things, that the civil investigation concerning certain generation procurement, dispatch, and transmission
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
system practices and policies of the Utility operating companies would remain open. The release noted, however, the intention of each of the Utility operating companies to join MISO and Entergy’s agreement with ITC to undertake the spin-off and merger of Entergy’s transmission business. The release stated that if Entergy follows through on these matters, the U.S. Department of Justice’s concerns will be resolved. The release further stated that the U.S. Department of Justice will monitor developments, and in the event that Entergy does not make meaningful progress, the U.S. Department of Justice can and will take appropriate enforcement action, if warranted.
Market and Credit Risk Sensitive Instruments
Market risk is the risk of changes in the value of commodity and financial instruments, or in future operating resultsnet income or cash flows, in response to changing market conditions. Entergy holds commodity and financial instruments that are exposed to the following significant market risks:risks.
| · | The commodity price risk associated with the sale of electricity by Entergy's Non-Utility Nuclear business and with the purchase of gas by the Utility.Entergy Wholesale Commodities business. |
| · | The interest rate and equity price risk associated with Entergy'sEntergy’s investments in pension and other postretirement benefit trust funds. See Note 11 to the financial statements for details regarding Entergy'sEntergy’s pension and other postretirement benefit trust funds. |
| · | The interest rate and equity price risk associated with Entergy'sEntergy’s investments in nuclear plant decommissioning trust funds, particularly in the Non-Utility NuclearEntergy Wholesale Commodities business. See Note 17 to the financial statements for details regarding Entergy'sEntergy’s decommissioning trust funds. |
| · | The interest rate risk associated with changes in interest rates as a result of Entergy'sEntergy’s issuances of debt. Entergy manages its interest rate exposure by monitoring current interest rates and its debt outstanding in relation to total capitalization. See Notes 4 and 5 to the financial statements for the details of Entergy'sEntergy’s debt outstanding. |
Entergy'sThe Utility business has limited exposure to the effects of market risk because it operates primarily under cost-based rate regulation. To the extent approved by their retail rate regulators, the Utility operating companies hedge the exposure to natural gas price volatility of their fuel and gas purchased for resale costs, which are recovered from customers.
Entergy’s commodity and financial instruments are also exposed to credit risk. Credit risk is the risk of loss from nonperformance by suppliers, customers, or financial counterparties to a contract or agreement. Credit riskEntergy is also includesexposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Commodity Price Risk
Power Generation
As a wholesale generator, Entergy's Non-Utility Nuclear business'sEntergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Non-Utility NuclearEntergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Non-Utility NuclearEntergy Wholesale Commodities sells unforced capacity, towhich allows load-serving entities which allows those companies to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Non-Utility Nuclear's Entergy Wholesale Commodities’ forward fixed pricephysical power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Non-Utility NuclearEntergy Wholesale Commodities to deliver MWh of energy, to its counterparties, make capacity available, to them, or both. In addition to its forward physical power contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, put and/or call options, to manage forward commodity price risk. Certain hedge volumes have price downside and upside relative to market price movement. The followingcontracted minimum, expected value,
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
and sensitivity are provided to show potential variations. While the sensitivity reflects the minimum, it does not reflect the total maximum upside potential from higher market prices. The information contained in the table below represents projections at a point in time and will vary over time based on numerous factors, such as future market prices, contracting activities, and generation. Following is a summary of Entergy Wholesale Commodities’ current forward capacity and generation contracts as well as total revenue projections based on market prices as of December 31, 2009 of the amount of Non-Utility Nuclear's nuclear power plants' planned energy output that is sold forward under physical or financial contracts:2012.
| | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
| Non-Utility Nuclear: | | | | | | | | | | |
| Percent of planned generation sold forward: | | | | | | | | | | |
| | Unit-contingent | | 53% | | 54% | | 18% | | 12% | | 14% |
| | Unit-contingent with guarantee of availability (1) | | 35% | | 17% | | 13% | | 6% | | 3% |
| | Firm liquidated damages | | 0% | | 3% | | 0% | | 0% | | 0% |
| | Total | | 88% | | 74% | | 31% | | 18% | | 17% |
| Planned generation (TWh) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average contracted price per MWh (2) | | $57 | | $56 | | $56 | | $50 | | $50 |
The following is a summary as of December 31, 2008 of the amount of Non-Utility Nuclear's nuclear power plants' planned energy output that is sold forward under physical or financial contracts:| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Unit-contingent (b) | | 42% | | 22% | | 12% | | 12% | | 13% |
Unit-contingent with availability guarantees (c) | | 19% | | 15% | | 13% | | 13% | | 13% |
Firm LD (d) | | 24% | | 55% | | 14% | | -% | | -% |
Offsetting positions (e) | | -% | | (19%) | | -% | | -% | | -% |
Total | | 85% | | 73% | | 39% | | 25% | | 26% |
| Planned generation (TWh) (f) (g) | | 40 | | 41 | | 41 | | 40 | | 41 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | | |
| Minimum | | $45 | | $44 | | $45 | | $50 | | $51 |
| Expected based on market prices as of Dec. 31, 2012 | | $46 | | $45 | | $47 | | $51 | | $52 |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$48 | | $44-$48 | | $45-$52 | | $50-$53 | | $51-$54 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Bundled capacity and energy contracts (i) | | 16% | | 16% | | 16% | | 16% | | 16% |
Capacity contracts (j) | | 33% | | 13% | | 12% | | 5% | | -% |
Total | | 49% | | 29% | | 28% | | 21% | | 16% |
| Planned net MW in operation (g) (k) | | 5,011 | | 5,011 | | 5,011 | | 5,011 | | 5,011 |
Average revenue under contract per kW per month (applies to Capacity contracts only) | | $2.3 | | $2.9 | | $3.3 | | $3.4 | | $- |
| | | | | | | | | | | |
| Total Nuclear Energy and Capacity Revenues | | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $45 | | $45 | | $47 | | $48 |
| Sensitivity: -/+ $10 per MWh market price change | | $47-$51 | | $42-$50 | | $38-$52 | | $40-$55 | | $41-$56 |
| | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 |
| Non-Utility Nuclear: | | | | | | | | | | |
| Percent of planned generation sold forward: | | | | | | | | | | |
| | Unit-contingent | | 48% | | 31% | | 29% | | 18% | | 12% |
| | Unit-contingent with guarantee of availability (1) | | 38% | | 35% | | 17% | | 7% | | 6% |
| | Total | | 86% | | 66% | | 46% | | 25% | | 18% |
| Planned generation (TWh) | | 41 | | 40 | | 41 | | 41 | | 40 |
| Average contracted price per MWh (2) | | $61 | | $60 | | $56 | | $54 | | $50 |
| | | 2013 | | 2014 | | 2015 | | 2016 | | 2017 |
| | | | | | | | | | | |
| Energy | | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | | |
Cost-based contracts (l) | | 39% | | 32% | | 35% | | 32% | | 32% |
Firm LD (d) | | 6% | | 6% | | 6% | | 6% | | 6% |
Total | | 45% | | 38% | | 41% | | 38% | | 38% |
| Planned generation (TWh) (f) (m) | | 6 | | 6 | | 6 | | 6 | | 6 |
| | | | | | | | | | | |
| Capacity | | | | | | | | | | |
| Percent of capacity sold forward (h): | | | | | | | | | | |
Cost-based contracts (l) | | 29% | | 24% | | 24% | | 24% | | 26% |
Bundled capacity and energy contracts (i) | | 8% | | 8% | | 8% | | 8% | | 9% |
Capacity contracts (j) | | 48% | | 47% | | 48% | | 20% | | -% |
Total | | 85% | | 79% | | 80% | | 52% | | 35% |
| Planned net MW in operation (k) (m) | | 1,052 | | 1,052 | | 1,052 | | 1,052 | | 977 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
(1)(a) | Percent of planned generation output sold or purchased forward under contracts, forward physical contracts, forward financial contracts, or options that mitigate price uncertainty that may require regulatory approval or approval of transmission rights. |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, seller is generally not liable to buyer for any damages. |
| (c) | A sale of power on a unit-contingent basis coupled with a guarantee of availability provides for the payment to the power purchaser of contract damages, if incurred, in the event the seller fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. All of Entergy'sEntergy’s outstanding guarantees of availability provide for dollar limits on Entergy'sEntergy’s maximum liability under such guarantees. |
(2)(d) | The Vermont Yankee acquisition includedTransaction that requires receipt or delivery of energy at a 10-year PPA under whichspecified delivery point (usually at a market hub not associated with a specific asset) or settles financially on notional quantities; if a party fails to deliver or receive energy, defaulting party must compensate the former owners will buy most of the power produced by the plant, which is through the expiration in 2012 of the current operating license for the plant. The PPA includes an adjustment clause under which the pricesother party as specified in the PPA willcontract, a portion of which may be adjusted downward monthly, beginningcapped through the use of risk management products. |
| (e) | Transactions for the purchase of energy, generally to offset a firm LD transaction. |
| (f) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that effect dispatch. |
| (g) | Assumes NRC license renewal for plants whose current licenses expire within five years and uninterrupted normal operation at all plants. NRC license renewal applications are in November 2005, ifprocess for two units, as follows (with current license expirations in parentheses): Indian Point 2 (September 2013) and Indian Point 3 (December 2015). For a discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. For a discussion regarding the license renewals for Indian Point 2 and Indian Point 3, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants” above. |
| (h) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
| (i) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
| (j) | A contract for the sale of an installed capacity product in a regional market. |
| (k) | Amount of capacity to be available to generate power market prices drop below PPA prices,and/or sell capacity considering uprates planned to be completed during the year. |
| (l) | Contracts priced in accordance with cost-based rates, a ratemaking concept used for the design and development of rate schedules to ensure that the filed rate schedules recover only the cost of providing the service; these contracts are on owned non-utility resources located within Entergy’s Utility service area, which hasdo not happened thus far.operate under market-based rate authority. The percentage sold assumes approval of long-term transmission rights. Includes sales to the Utility through 2013 of 121 MW of capacity and energy from Entergy Power sourced from Independence Steam Electric Station Unit 2. |
| (m) | Non-nuclear planned generation and net MW in operation include purchases from affiliated and non-affiliated counterparties under long-term contracts and exclude energy and capacity from Entergy Wholesale Commodities’ wind investment and from the 544 MW Ritchie plant that is not planned to operate. |
Entergy Corporationestimates that a positive $10 per MWh change in the annual average energy price in the markets in which the Entergy Wholesale Commodities nuclear business sells power, based on the respective year-end market conditions, planned generation volumes, and Subsidiaries
Management's Financial Discussionhedged positions, would have a corresponding effect on pre-tax net income of $125 million in 2013 and Analysiswould have had a corresponding effect on pre-tax net income of $48 million in 2012.
Entergy's Non-Utility Nuclear business'Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, NYPA and the subsidiaries that own the FitzPatrick and Indian Point 3 plants amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Entergy's Non-Utility Nuclear businessthe Entergy subsidiaries agreed to make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Entergy's Non-Utility Nuclear businessEntergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
million. The annual payment for each year'syear’s output is due by January 15 of the following year. In August 2008, Non-Utility Nuclear entered into a resolution of a dispute with NYPA over the applicability of the value sharing agreements to its FitzPatrick and Indian Point 3 nuclear power plants after the planned spin-off of the Non-Utility Nuclear business. Under the resolution, Non-Utility Nuclear agreed not to treat the separation as a "Cessation Event" that would terminate its obligation to make the payments under the value sharing agreements. As a result, after the spin-off transaction, Non-Utility Nuclear will continue to be obligated to make payments to NYPA under the amended and restated value sharing agreements.
Non-Utility NuclearEntergy will record itsthe liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2009, 2008,2012, 2011, and 2007, Non-Utility Nuclear2010, Entergy Wholesale Commodities recorded a liability of approximately $72 million liability for generation during each of those years. An amount equal to the liability was recorded each year to the plant asset account as contingent purchase price consideration for the plants. This amount will be depreciated over the expected remaining useful life of the plants.
Some of the agreements to sell the power produced by Entergy's Non-Utility NuclearEntergy Wholesale Commodities’ power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations under the agreements. The Entergy subsidiary is required to provide collateral based upon the difference between the current market and contracted power prices in the regions where Non-Utility NuclearEntergy Wholesale Commodities sells power. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of collateral. At December 31, 2009,2012, based on power prices at that time, Entergy had $369liquidity exposure of $203 million of collateralunder the guarantees in place to supportsupporting Entergy Nuclear Power Marketing transactional activity, consisting primarily of Entergy Corporation guarantees, but also includingWholesale Commodities transactions, $20 million of guarantees that support letters of credit, and $2$7 million of posted cash collateral.collateral to the ISOs. As of December 31, 2009,2012, the creditliquidity exposure associated with Non-Utility NuclearEntergy Wholesale Commodities assurance requirements, couldincluding return of previously posted collateral from counterparties, would increase by an estimated amount of up to $308$106 million for eacha $1 per MMBtu increase in gas prices in both the short- andshort-and long-term markets, but because market prices have fallen below most contract prices, the credit exposure would increase by only $8 million.markets. In the event of a decrease in Entergy Corporation'sCorporation’s credit rating to below investment grade, based on power prices as of December 31, 2009,2012, Entergy would have been required to provide approximately $73$48 million of additional cash or letters of credit under some of the agreements.
As of December 31, 2009,2012, substantially all of the counterparties or their guarantors for 100% of the planned energy output under contract for Non-Utility NuclearEntergy Wholesale Commodities nuclear plants through 2014, 99.7% of the planned energy output is under contract with counterparties with2016 have public investment grade credit ratingsratings.
Nuclear Matters
After the nuclear incident in Japan resulting from the March 2011 earthquake and 0.3%tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is with load-serving entitiesin the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
With the issuance of the three orders, the NRC also provided members of the public an opportunity to request a hearing. Two established anti-nuclear groups, Pilgrim Watch and Beyond Nuclear, filed hearing requests, focused on Pilgrim, regarding two of the three orders. These requests sought to have the NRC impose expanded remedial requirements to address the issues raised by the NRC’s orders. Beyond Nuclear subsequently withdrew its hearing request and the NRC’s ASLB denied Pilgrim Watch’s hearing request. Pilgrim Watch appealed the Board’s decision to the NRC, which affirmed the Board’s decision in January 2013.
On June 8, 2012, the U.S. Court of Appeals for the D.C. Circuit vacated the NRC’s 2010 update to its Waste Confidence Decision, which had found generically that a permanent geologic repository to store spent nuclear fuel would be available when necessary and that spent nuclear fuel could be stored at nuclear reactor sites in the interim without public credit ratings.significant environmental effects, and remanded the case for further proceedings. The court concluded that the NRC had not satisfied the requirements of the
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In additionNational Environmental Policy Act (NEPA) when it considered environmental effects in reaching these conclusions. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to sellingaddress some of the power produced by its plants,issues that NEPA requires the Non-Utility Nuclear business sells unforced capacityNRC to load-serving distribution companies in order for those companiesaddress before it issues a renewed license. Certain nuclear opponents filed requests with the NRC asking it to meet requirements placed on themaddress the issues raised by the ISOcourt’s decision in their area. Followingthe license renewal proceedings for a number of nuclear plants including Grand Gulf and Indian Point 2 and 3. On August 7, 2012 the NRC issued an order stating that it will not issue final licenses dependent upon the Waste Confidence Decision until the D.C. Circuit’s remand is addressed, but also stating that licensing reviews and proceedings should continue to move forward. On September 6, 2012 the NRC directed its staff to develop a summary of the amount of the Non-Utility Nuclear business' installed capacity that is currently sold forward, and the blended amount of the Non-Utility Nuclear business' planned generation output and installed capacity that is currently sold forward:
| | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
Non-Utility Nuclear: | | | | | | | | | | |
| Percent of capacity sold forward: | | | | | | | | | | |
| | Bundled capacity and energy contracts | | 26% | | 25% | | 18% | | 16% | | 16% |
| | Capacity contracts | | 42% | | 26% | | 30% | | 13% | | 0% |
| | Total | | 68% | | 51% | | 48% | | 29% | | 16% |
| Planned net MW in operation | | 4,998 | | 4,998 | | 4,998 | | 4,998 | | 4,998 |
| Average capacity contract price per kW per month | | $3.0 | | $3.6 | | $3.0 | | $2.6 | | $- |
| Blended Capacity and Energy (based on revenues) | | | | | | | | | | |
| % of planned generation and capacity sold forward | | 87% | | 73% | | 33% | | 16% | | 13% |
| Average contract revenue per MWh | | $59 | | $58 | | $60 | | $53 | | $50 |
Critical Accounting Estimates
The preparation of Entergy'sEntergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in thethese assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy'sEntergy’s financial position, or results of operations.operations, or cash flows.
Nuclear Decommissioning Costs
Entergy ownssubsidiaries own nuclear generation facilities in both itsthe Utility and Non-Utility NuclearEntergy Wholesale Commodities business units. Regulations require Entergy subsidiaries to decommission itsthe nuclear power plants after each facility is taken out of service, and money is collected and deposited in trust funds during the facilities'facilities’ operating lives in order to provide for this obligation. Entergy conducts periodic decommissioning cost studies to estimate the costs that will be incurred to decommission the facilities. The following key assumptions have a significant effect on these estimates:estimates.
| · | Cost Escalation Factors - Entergy'sEntergy’s current decommissioning cost studies include an assumption that decommissioning costs will escalate over present cost levels by annual factors ranging from approximately 3%2.0% to 3.5%3.25%. A 50 basis point change in this assumption could change the ultimate costestimated present value of the decommissioning a facilityliabilities by as much as an approximate average of 20%approximately 10% to 25%18%. To the extent that a high probability of license renewal is assumed, a change in the estimated inflation or cost escalation rate has a larger effect on the undiscounted cash flows because the rate of inflation is factored into the calculation for a longer period of time. |
| · | Timing - In projecting decommissioning costs, two assumptions must be made to estimate the timing of plant decommissioning. First, the date of the plant'splant’s retirement must be estimated. A high probability that the plant'splant’s license will be renewed and the plant will operate for some time beyond the original license term has currently been assumed for purposes of calculating the decommissioning liability for a number of Entergy'sEntergy’s nuclear units. Second, an assumption must be made whether decommissioning will begin immediately upon plant retirement, or whether the plant will be held in "safestore"SAFSTOR status for later decommissioning, as permitted by applicable regulations. SAFSTOR is decommissioning a facility by placing it in a safe, stable condition that is maintained until it is subsequently decontaminated and dismantled to levels that permit license termination, normally within 60 years from permanent cessation of operations. While the effect of these assumptions cannot be determined with precision, a change of assumption of either the probability of license renewal, continued operation, or use of a "safestore" statusSAFSTOR period can possibly change the present value of these obligations. Future revisions to appropriately reflect changes needed to the estimate of decommissioning costs will immediately affect net income for non-rate-regulated portions of Entergy’s business, and then only to the extent that the estimate of any reduction in the liability exceeds the amount of the undepreciated asset retirement cost at the date of the revision, for unregulated portions of Entergy's business.revision. Any increases in the liability recorded due to such changes are capitalized as asset retirement costs and depreciated over the asset'sasset’s remaining economic life. |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
| · | Spent Fuel Disposal - Federal law requires the DOE to provide for the permanent storage of spent nuclear fuel, and legislation has been passed by Congress to develop thisa repository at Yucca Mountain, Nevada. However, hearings on the repository’s NRC license have been suspended indefinitely. The DOE has not yet begun accepting spent nuclear fuel and is in non-compliance with federal law. The DOE continues to delay meeting its obligation and Entergy is continuing to pursue damages claims against the DOE for its failure to provide timely spent fuel storage. Until a federal site is available, however, nuclear plant operators must provide for interim spent fuel storage on the nuclear plant site, which can require the construction and maintenance of dry cask storage sites or other facilities. The costs of developing and maintaining these facilities during the decommissioning period can have a significant effect (as much as an average of 20% to 30% of total estimated decommissioning costs). Entergy'sEntergy’s decommissioning studies may include cost estimates for spent fuel storage. However, these estimates could change in the future based on the timing of the opening of an appropriate facility designated by the federal government to receive spent nuclear fuel. |
| · | Technology and Regulation –- Over the past several years, more practical experience with the actual decommissioning of facilities has been gained and that experience has been incorporated in to Entergy'sinto Entergy’s current decommissioning cost estimates. However, given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur and affect current cost estimates. If regulations regarding nuclear decommissioning were to change, this could have a potentially significant effect on cost estimates. The effect of these potential changes is not presently determinable. |
| · | Interest Rates - The estimated decommissioning costs that form the basis for the decommissioning liability recorded on the balance sheet are discounted to present values using a credit-adjusted risk-free rate. When the decommissioning cost estimate is significantly changed requiring a revision to the decommissioning liability and the change results in an increase in cash flows, that increase is discounted using a current credit-adjusted risk-free rate. Under accounting rules, if the revision in estimate results in a decrease in estimated cash flows, that decrease is discounted using the previous credit-adjusted risk-free rate. Therefore, to the extent that one of the factors noted above changes resulting in a significant increase in estimated cash flows, current interest rates will affect the calculation of the present value of the additional decommissioning liability. |
In the firstsecond quarter 2009,2012, Entergy ArkansasLouisiana recorded a revision to its estimated decommissioning cost liabilitiesliability for ANO 1 and 2Waterford 3 as a result of a revised decommissioning cost study. The revised estimatesestimate resulted in an $8.9a $48.9 million reductionincrease in its decommissioning cost liability, along with a corresponding increase in the related asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the related regulatoryliability over the amount of the undepreciated asset retirement costs asset.
In the secondfirst quarter 2009,2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $4.2$38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2009,2011, Entergy Gulf States LouisianaWholesale Commodities recorded a revision toreduction of $34.1 million in its estimated decommissioning cost liability for River Benda plant as a result of a revised decommissioning cost study.study obtained to comply with a state regulatory requirement. The revised estimatecost study resulted in a $78.7 million increase in its decommissioning liability, along with a corresponding increasechange in the related asset retirement obligation asset that will be depreciatedundiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the remaining lifeamount of the unit.undepreciated assets.
In the third quarter 2008, Entergy's Non-Utility Nuclear business recorded an increase of $13.7 million in decommissioning liabilities for certain of its plants as a result of revised decommissioning cost studies. The revised estimates resulted in the recognition of a $13.7 million asset retirement obligation asset that will be depreciated over the remaining life of the units.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Impairment of Long-lived Assets and Trust Fund Investments
Entergy has significant investments in long-lived assets in all of its segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment whenever there are indications that impairments may exist. This evaluation involves a significant degree of estimation and uncertainty. In the UtilityEntergy Wholesale Commodities business, portions of River Bend are not included in rate base, which could reduce the revenue that would otherwise be recovered for the applicable portions of its generation. In the Non-Utility Nuclear business, Entergy'sEntergy’s investments in merchant nuclear generation assets are subject to impairment if adverse market conditions arise, if a unit plans to cease, or ceases, operation sooner than expected, or for certain units if their operating licenses are not renewed. In the non-nuclear wholesale assets business, Entergy'sEntergy’s investments in merchant non-nuclear generation assets are subject to impairment if adverse market conditions arise.arise or if a unit plans to cease, or ceases, operation sooner than expected.
In order to determine if Entergy should recognize an impairment of a long-lived asset that is to be held and used, accounting standards require that the sum of the expected undiscounted future cash flows from the asset be compared to the asset'sasset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the recording of an additional decommissioning liability, therefore changes in assumptions that affect the decommissioning liability can increase or decrease the carrying value of the asset subject to impairment. If the expected undiscounted future cash flows exceed the carrying value, no impairment is recorded; if such cash flows are less than the carrying value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is held for sale, an impairment is required to be recognized if the fair value (less costs to sell) of the asset is less than its carrying value.
These estimates are based on a number of key assumptions, including:
| · | Future power and fuel prices - Electricity and gas prices have been very volatile in recent years, and this volatility is expected to continue. This volatility necessarily increases the imprecision inherent in the long-term forecasts of commodity prices that are a key determinant of estimated future cash flows. |
| · | Market value of generation assets - Valuing assets held for sale requires estimating the current market value of generation assets. While market transactions provide evidence for this valuation, the market for such assets is volatile and the value of individual assets is impacted by factors unique to those assets. |
| · | Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant impact on operations could cause a significant change in these assumptions. |
| · | Timing - Entergy currently assumes, for a number of its nuclear units, that the plant'splant’s license will be renewed. A change in that assumption could have a significant effect on the expected future cash flows and result in a significant effect on operations. |
Entergy's Non-Utility Nuclear business currently has pending applications for license renewals forFor additional discussion regarding the continued operation of the Vermont Yankee Pilgrim, Indian Point 2, and Indian Point 3 power plants. In addition, for Vermont Yankeeplant, see “Impairment of Long-Lived Assets” in Note 1 to the state certificates of public good to operate the plant and store spent nuclear fuel also expire in 2012. Non-Utility Nuclear filed an application with the Vermont Public Service Board on March 3, 2008 for approval of continued operations and storage of spent nuclear fuel generated after March 21, 2012. Under Vermont law the Vermont General Assembly approval of Non-Utility Nuclear's request is required for the request to be granted. On February 24, 2010, a bill to approve the continued operation offinancial statements.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Vermont Yankee was advanced to a vote by the Vermont Senate leadership and defeated by a margin of 26 to 4. This vote does not preclude the Vermont Senate from voting again on a similar bill in the future. At the current time, Entergy management believes that it will ultimately receive all necessary approvals to operate Vermont Yankee beyond its current license expiration. If those approvals are ultimately not received, it could result in an impairment of part or all of the carrying value of the plant, including any capitalized asset retirement cost associated with the recording of the decommissioning liability as further described in Note 9 to the financial statements.
Effective January 1, 2009, Entergy adoptedevaluates unrealized losses at the end of each period to determine whether an accounting pronouncement providing guidance regarding recognition and presentation of other-than-temporary impairments related to investments in debt securities.impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary-impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). For debt securities held as of January 1, 2009 for which an other-than-temporary impairment had previously been recognized but for which assessment under the new guidance indicates this impairment is temporary, Entergy recorded an adjustment to its opening balance of retained earnings of $11.3 million ($6.4 million net-of-tax). Entergy did not have any material other than temporary impairments relating to credit losses on debt securities in 2009.2012, 2011, or 2010. The assessment of whether an investment in an equity security has suffered an other than temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy'sEntergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. As discloseddiscussed in Note 1 to the financial statements, unrealized losses that are not considered temporarily impaired are recorded in earnings for Non-Utility Nuclear. Non-Utility Nuclear recordedEntergy Wholesale Commodities. Entergy Wholesale Commodities did not record material charges to other income of $86 million in 2009, $50 million in 2008,2012, 2011, and $5 million in 20072010, respectively, resulting from the recognition of impairmentsthe other-than-temporary impairment of certain equity securities held in its decommissioning trust funds that are not considered temporary.funds. Additional impairments could be recorded in 20102013 to the extent that then current market conditions change the evaluation of recoverability of unrealized losses.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate for the Utility and Non-Utility NuclearEntergy Wholesale Commodities segments.
Assumptions
Key actuarial assumptions utilized in determining these costs include:
| · | Discount rates used in determining the future benefit obligations; |
| · | Projected health care cost trend rates; |
| · | Expected long-term rate of return on plan assets; and |
| · | Rate of increase in future compensation levels.levels; |
Entergy reviews thesethe first four assumptions listed above on an annual basis and adjusts them as necessary. The falling interest rate environment and worse-than-expected performance ofvolatility in the financial equity markets in recent years have impacted Entergy'sEntergy’s funding and reported costs for these benefits. In addition, these trends have caused Entergy to make a number of adjustments to its assumptions.
The retirement and mortality rate assumptions are reviewed every three to five years as part of an actuarial study that compares these assumptions to the actual experience of the pension and other postretirement plans. The 2011 actuarial study reviewed plan experience from 2007 through 2010. As a result of the 2011 actuarial study, changes were made to reflect the expectation that participants have longer life expectancies and different retirement patterns than previously assumed. These changes are reflected in the December 31, 2012 and December 31, 2011 financial disclosures.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
In selecting an assumed discount rate to calculate benefit obligations, Entergy reviews market yields on high-quality corporate debt and matches these rates with Entergy'sEntergy’s projected stream of benefit payments. Based on recent market trends, Entergy decreased the discount raterates used to calculate its 2012 qualified pension benefit obligation and 2013 qualified pension cost ranged from an average4.31% to 4.50% for its specific pension plans (4.36% combined rate of 6.75% in 2008for all pension plans). The discount rates used to calculate its 2011 qualified pension benefit obligation and 2012 qualified pension cost ranged from 5.1% to 5.2% for its specific rates by plan ranging from 6.10% to 6.30% in 2009.pension plans (5.1% combined rate for all pension plans). The discount rate used to calculate its other 2012 postretirement benefit obligation and 2013 postretirement benefit cost was also decreased from 6.7% in 2008 to 6.10% in 2009. Entergy's assumed4.36%. The discount rate used to calculate the 2007 pension andits 2011 other postretirement benefit obligationsobligation and 2012 postretirement benefit cost was 6.50%5.1%.
Entergy reviews actual recent cost trends and projected future trends in establishing health care cost trend rates. Based on this review, Entergy'sEntergy’s assumed health care cost trend rate assumption used in calculatingmeasuring the December 31, 20092012 accumulated postretirement benefit obligation and 2013 postretirement cost was a 7.5% increase in health care costs in 20107.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches a 4.75% annualin 2022 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2011 accumulated postretirement benefit obligation and 2012 postretirement cost was 7.75% for pre-65 retirees and 7.5% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumed rate of increase in health care costs in 2016future compensation levels used to calculate 2012 and beyond.2011 benefit obligations was 4.23%.
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past long-term performance, current and expected future asset allocations, and long-term inflation assumptions.capital market assumptions of its investment consultant and investment managers.
Since 2003, Entergy targetshas targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. Entergy completed and adopted an optimization study in 2011 for the pension assets which recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current to its ultimate allocation of 45% equity, 55% fixed income. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for Entergy'sEntergy’s non-taxable postretirement benefit assets are 55%65% equity securities and 45%35% fixed-income securities and, for its taxable other postretirement benefit assets, 35%65% equity securities and 65%35% fixed-income securities. Entergy'sThis takes into account asset allocation adjustments that were made during 2012.
Entergy’s expected long-termlong term rate of return on qualified pension assets used to calculate 2012, 2011 and 2010 qualified pension costs was 8.5% and will be 8.5% for 2013. Entergy’s expected long term rate of return on non-taxable other postretirement assets used to calculate 2009, 2008, and 2007 qualified pension and other postretirement benefits costs was 8.5%. Entergy's for 2012 and 2011, 7.75% for 2010 and will be 8.5% for 2013. For Entergy’s taxable postretirement assets, the expected long-termlong term rate of return on taxable other postretirement assets was 6%6.5% for 2012, 5.5% for 2011 and 2010, and will be 6.5% in 2009 and 5.5% in 2008 and 2007.2013.
The assumed rate
Entergy Corporation and 2007.Subsidiaries
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified pension projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) | | Increase/(Decrease) |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $12,192 | | $117,856 | | (0.25%) | | $20,142 | | $229,473 |
| Rate of return on plan assets | | (0.25%) | | $7,331 | | - | | (0.25%) | | $9,337 | | $- |
| Rate of increase in compensation | | 0.25% | | $6,311 | | $30,817 | | 0.25% | | $8,512 | | $48,036 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Health care cost trend | | 0.25% | | $6,073 | | $31,981 |
| Discount rate | | (0.25%) | | $4,109 | | $37,324 |
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis.
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $8,061 | | $72,947 |
| Health care cost trend | | 0.25% | | $11,422 | | $64,967 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Accounting Mechanisms
Effective December 31, 2006, accountingAccounting standards requiredrequire an employer to recognize in its balance sheet the funded status of its benefit plans. Refer to Note 11 to the financial statements for a further discussion of Entergy'sEntergy’s funded status.
In accordance with pension accounting standards, Entergy utilizes a number of accounting mechanisms that reduce the volatility of reported pension costs. Differences between actuarial assumptions and actual plan results are deferred and are amortized into expense only when the accumulated differences exceed 10% of the greater of the projected benefit obligation or the market-related value of plan assets. If necessary, the excess is amortized over the average remaining service period of active employees.
Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Costs and Funding
In 2009, Entergy's2012, Entergy’s total qualified pension cost was $86$264 million. Entergy anticipates 20102013 qualified pension cost to be $147.1$332 million. Pension funding was $132approximately $170.5 million for 2009. Entergy's2012. Entergy’s contributions to the pension trust are currently estimated to be approximately $270$163.3 million in 2010,2013, although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010.2013.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Minimum required funding calculations as determined under Pension Protection Act guidance are performed annually as of January 1 of each year and are based on measurements of the assets and funding liabilities as measured at that date. Any excess of the funding liability over the calculated fair market value of assets results in a funding shortfall which, under the Pension Protection Act, must be funded over a seven-year rolling period. The Pension Protection Act also imposes certain plan limitations if the funded percentage, which is based on a calculated fair market values of assets divided by funding liabilities, does not meet certain thresholds. For funding purposes, asset gains and losses are smoothed in to the calculated fair market value of assets and the funding liability is based upon a weighted average 24-month corporate bond rate published by the U.S. Treasury; therefore, periodic changes in asset returns and interest rates can affect funding shortfalls and future cash contributions.
Entergy's minimum required contributionsThe Moving Ahead for the 2010 plan year are generally payable in installments throughout 2010 and 2011 and will be based on the funding calculations as of January 1, 2010. The final date at which 2010 plan year contributions may be made is September 15, 2011. Given the declineProgress in the capital markets21st Century Act (MAP-21) became federal law on July 6, 2012. Under the law, the segment rates used to calculate funding liabilities must be within a corridor of the 25-year average of prior segment rates. The interest rate corridor applies to the determination of minimum funding requirements and benefit restrictions. The pension funding stabilization provisions will provide for a near-term reduction in 2008,minimum funding requirements for single employer defined benefit plans in response to the minimum requiredcurrent, historically low interest rates. The law does not reduce contribution requirements over the long term, and it is likely that Entergy’s contributions forto the 2010 plan year, payable in 2010 and 2011,pension trust will increase although recoveries in the capital market in 2009 will help to mitigate the expected increase. The actual increase or timing of that increase cannot be determined with certainty until the January 1, 2010 valuation is completed by April 1, 2010; however Entergy’s preliminary estimates of 2010 funding requirements indicate that the contributions will not increase materially over and above historical levels of pension contributions. In addition to the minimum required contribution required under the Pension Protection Act to fund a shortfall based on the seven year rolling amortization, additional contributions could be needed in 2010 to avoid the plan limitations noted above.after 2013.
Total postretirement health care and life insurance benefit costs for Entergy in 20092012 were $105.2$138.4 million, including $24$31.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy expects 20102013 postretirement health care and life insurance benefit costs to be $111$146.8 million. This includes a projected $26.6$34 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy contributed $79$82.2 million to its postretirement plans in 2009.2012. Entergy’s current estimate of contributions to its other postretirement plans is approximately $76.4$82.5 million in 2010.2013.
Federal Healthcare Legislation
The Patient Protection and Affordable Care Act (PPACA) became federal law on March 23, 2010, and, on March 30, 2010, the Health Care and Education Reconciliation Act of 2010 became federal law and amended certain provisions of the PPACA. These new federal laws change the law governing employer-sponsored group health plans, like Entergy's plans, and include, among other things, the following significant provisions.
| · | A 40% excise tax on per capita medical benefit costs that exceed certain thresholds; |
| · | Change in coverage limits for dependents; and |
| · | Elimination of lifetime caps. |
The effect of PPACA has been reflected based on Entergy’s understanding of current guidance on the rules and regulations. However, there are still many technical issues that have not been finalized. Entergy will continue to monitor these developments to determine the possible impact on Entergy as a result of PPACA. Entergy is participating in the programs currently provided for under PPACA, such as the early retiree reinsurance program, which has provided for some limited reimbursements of certain claims for early retirees aged 55 to 64 who are not yet eligible for Medicare.
One provision of the new law that is effective in 2013 eliminates the federal income tax deduction for prescription drug expenses of Medicare beneficiaries for which the plan sponsor also receives the retiree drug subsidy under Part D. Entergy receives subsidy payments under the Medicare Part D plan and therefore in the first quarter 2010 recorded a reduction to the deferred tax asset related to the unfunded other postretirement benefit obligation. The offset was recorded in 2010 as a $16 million charge to income tax expense or, for the Utility, including each Registrant Subsidiary, as a regulatory asset.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
Other Contingencies
As a company with multi-state domestic utility operations, and a history of international investments, Entergy is subject to a number of federal state, and internationalstate laws and regulations and other factors and conditions in the areas in which it operates, which potentially subject it to environmental, litigation, and other risks. Entergy periodically evaluates its exposure for such risks and records a reserve for those matters which are considered probable and estimable in accordance with generally accepted accounting principles.
Environmental
Entergy must comply with environmental laws and regulations applicable to the handlingair emissions, water discharges, solid and disposal of hazardous waste.waste, toxic substances, protected species, and other environmental matters. Under these various laws and regulations, Entergy could incur substantial costs to restore properties consistent withcomply or address any impacts to the various standards.environment. Entergy conducts studies to determine the extent of any required remediation and has recorded reserves based upon its evaluation of the likelihood of loss and expected dollar amount for each issue. Additional sites or issues could be identified which require environmental remediation or corrective action for which Entergy could be liable. The amounts of environmental reserves recorded can be significantly affected by the following external events or conditions:conditions.
| · | Changes to existing state or federal regulation by governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. |
| · | The identification of additional impacts, sites, issues, or the filing of other complaints in which Entergy may be asserted to be a potentially responsible party. |
| · | The resolution or progression of existing matters through the court system or resolution by the EPA.EPA or relevant state or local authority. |
Litigation
Entergy has beenis regularly named as a defendant in a number of lawsuits involving employment, ratepayer,customers, and injuries and damages issues, among other matters. Entergy periodically reviews the cases in which it has been named as defendant and assesses the likelihood of loss in each case as probable, reasonably estimable, or remote and records reserves for cases which have a probable likelihood of loss and can be estimated. Notes 2 and 8 to the financial statements include more detail on ratepayer and other lawsuits and management's assessment of the adequacy of reserves recorded for these matters. Given the environment in which Entergy operates, and the unpredictable nature of many of the cases in which Entergy is named as a defendant, however, the ultimate outcome of the litigation to which Entergy is exposed to has the potential to materially affect the results of operations of Entergy or its operating company subsidiaries.Registrant Subsidiaries.
Uncertain Tax Positions
Entergy'sEntergy’s operations, including acquisitions and divestitures, require Entergy to evaluate risks such as the potential tax effects of a transaction, or warranties made in connection with such a transaction. Entergy believes that it has adequately assessed and provided for these types of risks, where applicable. Any reservesprovisions recorded for these types of issues, however, could be significantly affected by events such as claims made by third parties under warranties, additional transactions contemplated by Entergy, or completion of reviews of the tax treatment of certain transactions or issues by taxing authorities. Entergy does not expect a material adverse effect on earnings from these matters.
Entergy Corporation and Subsidiaries
Management's Financial Discussion and Analysis
New Accounting Pronouncements
In June 2009The accounting standard-setting process, including projects between the FASB issued SFAS 167, "Amendmentsand the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB Interpretation No. 46R". SFAS 167 replacesand the current quantitative-based risks and rewards calculation for determining which enterprise, if any, hasIASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a controllingmaterial effect on Entergy’s future net income, financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity that most significantly affect the entity's economic performance and (1) the obligation to absorb losses of the entityposition, or (2) the right to receive benefits from the entity. SFAS 167 also requires additional disclosures on an interim and annual basis about an enterprise's involvement in variable interest entities. The standard will be effective for Entergy in the first quarter 2010. Upon adoption, Entergy expects its subsidiaries that finance their nuclear fuel purchases through nuclear fuel leases to consolidate the special purpose nuclear fuel companies acting as lessors. The adoption of this statement will result in the reclassification of amounts between certain line items in the financial statements.cash flows.
ENTERGY CORPORATION AND SUBSIDIARIES
REPORT OF MANAGEMENT
| ENTERGY CORPORATION AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,745,650 | | | $ | 13,093,756 | | | $ | 11,484,398 | | | $ | 10,932,158 | | | $ | 10,106,247 | |
| Income from continuing operations | | $ | 1,231,092 | | | $ | 1,220,566 | | | $ | 1,134,849 | | | $ | 1,133,098 | | | $ | 943,125 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 6.39 | | | $ | 6.39 | | | $ | 5.77 | | | $ | 5.46 | | | $ | 4.49 | |
| Diluted | | $ | 6.30 | | | $ | 6.20 | | | $ | 5.60 | | | $ | 5.36 | | | $ | 4.40 | |
| Dividends declared per share | | $ | 3.00 | | | $ | 3.00 | | | $ | 2.58 | | | $ | 2.16 | | | $ | 2.16 | |
| Return on common equity | | | 14.85 | % | | | 15.42 | % | | | 14.13 | % | | | 14.21 | % | | | 11.20 | % |
| Book value per share, year-end | | $ | 45.54 | | | $ | 42.07 | | | $ | 40.71 | | | $ | 40.45 | | | $ | 37.31 | |
| Total assets | | $ | 37,364,597 | | | $ | 36,616,818 | | | $ | 33,643,002 | | | $ | 31,082,731 | | | $ | 30,857,657 | |
| Long-term obligations (1) | | $ | 11,059,971 | | | $ | 11,517,382 | | | $ | 9,948,573 | | | $ | 8,996,620 | | | $ | 9,013,448 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), preferred stock with sinking fund, and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | |
| | | (Dollars In Millions) |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 2,999 | | | $ | 3,610 | | | $ | 3,228 | | | $ | 3,193 | | | $ | 2,912 | |
| Commercial | | | 2,184 | | | | 2,735 | | | | 2,413 | | | | 2,318 | | | | 2,041 | |
| Industrial | | | 1,997 | | | | 2,933 | | | | 2,545 | | | | 2,630 | | | | 2,419 | |
| Governmental | | | 204 | | | | 248 | | | | 221 | | | | 155 | | | | 141 | |
| Total retail | | | 7,384 | | | | 9,526 | | | | 8,407 | | | | 8,296 | | | | 7,513 | |
| Sales for resale (1) | | | 206 | | | | 325 | | | | 393 | | | | 612 | | | | 656 | |
| Other | | | 290 | | | | 222 | | | | 246 | | | | 155 | | | | 278 | |
| Total | | $ | 7,880 | | | $ | 10,073 | | | $ | 9,046 | | | $ | 9,063 | | | $ | 8,447 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 33,626 | | | | 33,047 | | | | 33,281 | | | | 31,665 | | | | 31,569 | |
| Commercial | | | 27,476 | | | | 27,340 | | | | 27,408 | | | | 25,079 | | | | 24,401 | |
| Industrial | | | 35,638 | | | | 37,843 | | | | 38,985 | | | | 38,339 | | | | 37,615 | |
| Governmental | | | 2,408 | | | | 2,379 | | | | 2,339 | | | | 1,580 | | | | 1,568 | |
| Total retail | | | 99,148 | | | | 100,609 | | | | 102,013 | | | | 96,663 | | | | 95,153 | |
| Sales for resale (1) | | | 4,862 | | | | 5,401 | | | | 6,145 | | | | 10,803 | | | | 11,459 | |
| Total | | | 104,010 | | | | 106,010 | | | | 108,158 | | | | 107,466 | | | | 106,612 | |
| | | | | | | | | | | | | | | | | | | | | |
| Non-Utility Nuclear: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,555 | | | $ | 2,558 | | | $ | 2,030 | | | $ | 1,545 | | | $ | 1,422 | |
| Billed Electric Energy Sales (GWh) | | | 40,981 | | | | 41,710 | | | | 37,570 | | | | 34,847 | | | | 33,641 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes sales to Entergy New Orleans, which was deconsolidated in 2006 and 2005. See Note 18 to the financial statements. | |
| | | | | | | | | | | | | | | | | | | | | |
Entergy management assesses the design and effectiveness of Entergy’s internal control over financial reporting on an annual basis. In making this assessment, management uses the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Management acknowledges, however, that all internal control systems, no matter how well designed, have inherent limitations and can provide only reasonable assurance with respect to financial statement preparation and presentation.
Entergy Corporation and the Registrant Subsidiaries’ independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy’s internal control over financial reporting as of December 31, 2012, which is included herein on pages 416 through 423.
In addition, the Audit Committee of the Board of Directors, composed solely of independent Directors, meets with the independent auditors, internal auditors, management, and internal accountants periodically to discuss internal controls, and auditing and financial reporting matters. The Audit Committee appoints the independent auditors annually, seeks shareholder ratification of the appointment, and reviews with the independent auditors the scope and results of the audit effort. The Audit Committee also meets periodically with the independent auditors and the chief internal auditor without management present, providing free access to the Audit Committee.
Based on management’s assessment of internal controls using the COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2012. Management further believes that this assessment, combined with the policies and procedures noted above, provides reasonable assurance that Entergy’s and each of the Registrant Subsidiaries’ financial statements are fairly and accurately presented in accordance with generally accepted accounting principles.
LEO P. DENAULT Chairman of the Board and Chief Executive Officer of Entergy Corporation | ANDREW S. MARSH Executive Vice President and Chief Financial Officer of Entergy Corporation |
HUGH T. MCDONALD Chairman of the Board, President, and Chief Executive Officer of Entergy Arkansas, Inc. | PHILLIP R. MAY, JR. Chairman of the Board, President, and Chief Executive Officer of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC |
HALEY R. FISACKERLY Chairman of the Board, President, and Chief Executive Officer of Entergy Mississippi, Inc. | CHARLES L. RICE, JR. Chairman of the Board, President and Chief Executive Officer of Entergy New Orleans, Inc. |
SALLIE T. RAINER Chair of the Board, President, and Chief Executive Officer of Entergy Texas, Inc. | JEFFREY S. FORBES Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
ALYSON M. MOUNT Senior Vice President and Chief Accounting Officer (and acting principal financial officer) of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., and Entergy Texas, Inc. | WANDA C. CURRY Vice President and Chief Financial Officer of System Energy Resources, Inc. |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands, Except Percentages and Per Share Amounts) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 10,302,079 | | | $ | 11,229,073 | | | $ | 11,487,577 | | | $ | 10,745,650 | | | $ | 13,093,756 | |
| Income from continuing operations | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | | | $ | 1,251,050 | | | $ | 1,240,535 | |
| Earnings per share from continuing operations: | | | | | | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | | | $ | 6.39 | | | $ | 6.39 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | | | $ | 6.30 | | | $ | 6.20 | |
| Dividends declared per share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | | | $ | 3.00 | | | $ | 3.00 | |
| Return on common equity | | | 9.33 | % | | | 15.43 | % | | | 14.61 | % | | | 14.85 | % | | | 15.42 | % |
| Book value per share, year-end | | $ | 51.72 | | | $ | 50.81 | | | $ | 47.53 | | | $ | 45.54 | | | $ | 42.07 | |
| Total assets | | $ | 43,202,502 | | | $ | 40,701,699 | | | $ | 38,685,276 | | | $ | 37,561,953 | | | $ | 36,616,818 | |
| Long-term obligations (1) | | $ | 12,141,370 | | | $ | 10,268,645 | | | $ | 11,575,973 | | | $ | 11,277,314 | | | $ | 11,734,411 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Utility Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 3,022 | | | $ | 3,369 | | | $ | 3,375 | | | $ | 2,999 | | | $ | 3,610 | |
| Commercial | | | 2,174 | | | | 2,333 | | | | 2,317 | | | | 2,184 | | | | 2,735 | |
| Industrial | | | 2,034 | | | | 2,307 | | | | 2,207 | | | | 1,997 | | | | 2,933 | |
| Governmental | | | 198 | | | | 205 | | | | 212 | | | | 204 | | | | 248 | |
| Total retail | | | 7,428 | | | | 8,214 | | | | 8,111 | | | | 7,384 | | | | 9,526 | |
| Sales for resale | | | 179 | | | | 216 | | | | 389 | | | | 206 | | | | 325 | |
| Other | | | 264 | | | | 244 | | | | 241 | | | | 290 | | | | 222 | |
| Total | | $ | 7,871 | | | $ | 8,674 | | | $ | 8,741 | | | $ | 7,880 | | | $ | 10,073 | |
| Utility Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 34,664 | | | | 36,684 | | | | 37,465 | | | | 33,626 | | | | 33,047 | |
| Commercial | | | 28,724 | | | | 28,720 | | | | 28,831 | | | | 27,476 | | | | 27,340 | |
| Industrial | | | 41,181 | | | | 40,810 | | | | 38,751 | | | | 35,638 | | | | 37,843 | |
| Governmental | | | 2,435 | | | | 2,474 | | | | 2,463 | | | | 2,408 | | | | 2,379 | |
| Total retail | | | 107,004 | | | | 108,688 | | | | 107,510 | | | | 99,148 | | | | 100,609 | |
| Sales for resale | | | 3,200 | | | | 4,111 | | | | 4,372 | | | | 4,862 | | | | 5,401 | |
| Total | | | 110,204 | | | | 112,799 | | | | 111,882 | | | | 104,010 | | | | 106,010 | |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | |
| Operating Revenues | | $ | 2,326 | | | $ | 2,414 | | | $ | 2,566 | | | $ | 2,711 | | | $ | 2,794 | |
| Billed Electric Energy Sales (GWh) | | | 46,178 | | | | 43,497 | | | | 42,934 | | | | 43,743 | | | | 44,875 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20092012 and 2008,2011, and the related consolidated income statements, consolidated statements of income, retained earnings, comprehensive income, and paid-in capital, andconsolidated statements of cash flows, and consolidated statements of changes in equity for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Corporation’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Corporation and Subsidiaries as of December 31, 20092012 and 2008,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, the Corporation adopted a new accounting standard for non-controlling interests for all periods presented.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Corporation’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,870,649 | | | $ | 8,673,517 | | | $ | 8,740,637 | |
| Natural gas | | | 130,836 | | | | 165,819 | | | | 197,658 | |
| Competitive businesses | | | 2,300,594 | | | | 2,389,737 | | | | 2,549,282 | |
| TOTAL | | | 10,302,079 | | | | 11,229,073 | | | | 11,487,577 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,036,835 | | | | 2,492,714 | | | | 2,518,582 | |
| Purchased power | | | 1,255,800 | | | | 1,564,967 | | | | 1,659,416 | |
| Nuclear refueling outage expenses | | | 245,600 | | | | 255,618 | | | | 256,123 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Other operation and maintenance | | | 3,045,392 | | | | 2,867,758 | | | | 2,969,402 | |
| Decommissioning | | | 184,760 | | | | 190,595 | | | | 211,736 | |
| Taxes other than income taxes | | | 557,298 | | | | 536,026 | | | | 534,299 | |
| Depreciation and amortization | | | 1,144,585 | | | | 1,102,202 | | | | 1,069,894 | |
| Other regulatory charges - net | | | 175,104 | | | | 205,959 | | | | 44,921 | |
| TOTAL | | | 9,000,898 | | | | 9,215,839 | | | | 9,264,373 | |
| | | | | | | | | | | | | |
| Gain on sale of business | | | - | | | | - | | | | 44,173 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 1,301,181 | | | | 2,013,234 | | | | 2,267,377 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 92,759 | | | | 84,305 | | | | 59,381 | |
| Interest and investment income | | | 127,776 | | | | 128,994 | | | | 184,077 | |
| Miscellaneous - net | | | (53,214 | ) | | | (59,271 | ) | | | (48,124 | ) |
| TOTAL | | | 167,321 | | | | 154,028 | | | | 195,334 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 606,596 | | | | 551,521 | | | | 610,146 | |
| Allowance for borrowed funds used during construction | | | (37,312 | ) | | | (37,894 | ) | | | (34,979 | ) |
| TOTAL | | | 569,284 | | | | 513,627 | | | | 575,167 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 899,218 | | | | 1,653,635 | | | | 1,887,544 | |
| | | | | | | | | | | | | |
| Income taxes | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 4.77 | | | $ | 7.59 | | | $ | 6.72 | |
| Diluted | | $ | 4.76 | | | $ | 7.55 | | | $ | 6.66 | |
| Dividends declared per common share | | $ | 3.32 | | | $ | 3.32 | | | $ | 3.24 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 177,324,813 | | | | 177,430,208 | | | | 186,010,452 | |
| Diluted average number of common shares outstanding | | | 177,737,565 | | | | 178,370,695 | | | | 187,814,235 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | | | | | | | |
| (net of tax expense (benefit) of ($55,750), $34,411, and ($7,088) | | | (97,591 | ) | | | 71,239 | | | | (11,685 | ) |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax benefit of $61,223, $131,198, and $14,387) | | | (91,157 | ) | | | (223,090 | ) | | | (8,527 | ) |
| Net unrealized investment gains | | | | | | | | | | | | |
| (net of tax expense of $61,104, $19,368, and $51,130) | | | 63,609 | | | | 21,254 | | | | 57,523 | |
| Foreign currency translation | | | | | | | | | | | | |
| (net of tax expense (benefit) of $275, $192, and ($182)) | | | 508 | | | | 357 | | | | (338 | ) |
| Other comprehensive income (loss) | | | (124,631 | ) | | | (130,240 | ) | | | 36,973 | |
| | | | | | | | | | | | | |
| Comprehensive Income | | | 743,732 | | | | 1,237,132 | | | | 1,307,278 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| | | | | | | | | | | | | |
| Comprehensive Income Attributable to Entergy Corporation | | $ | 722,042 | | | $ | 1,216,199 | | | $ | 1,287,215 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 868,363 | | | $ | 1,367,372 | | | $ | 1,270,305 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 1,771,649 | | | | 1,745,455 | | | | 1,705,331 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (26,479 | ) | | | (280,029 | ) | | | 718,987 | |
| Asset impairment | | | 355,524 | | | | - | | | | - | |
| Gain on sale of business | | | - | | | | - | | | | (44,173 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (14,202 | ) | | | 28,091 | | | | (99,640 | ) |
| Fuel inventory | | | (11,604 | ) | | | 5,393 | | | | (10,665 | ) |
| Accounts payable | | | (6,779 | ) | | | (131,970 | ) | | | 216,635 | |
| Prepaid taxes and taxes accrued | | | 55,484 | | | | 580,042 | | | | (116,988 | ) |
| Interest accrued | | | 1,152 | | | | (34,172 | ) | | | 17,651 | |
| Deferred fuel costs | | | (99,987 | ) | | | (55,686 | ) | | | 8,909 | |
| Other working capital accounts | | | (151,989 | ) | | | 41,875 | | | | (160,326 | ) |
| Changes in provisions for estimated losses | | | (24,808 | ) | | | (11,086 | ) | | | 265,284 | |
| Changes in other regulatory assets | | | (398,428 | ) | | | (673,244 | ) | | | 339,408 | |
| Changes in pensions and other postretirement liabilities | | | 644,099 | | | | 962,461 | | | | (80,844 | ) |
| Other | | | (21,710 | ) | | | (415,685 | ) | | | (103,793 | ) |
| Net cash flow provided by operating activities | | | 2,940,285 | | | | 3,128,817 | | | | 3,926,081 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (2,674,650 | ) | | | (2,040,027 | ) | | | (1,974,286 | ) |
| Allowance for equity funds used during construction | | | 96,131 | | | | 86,252 | | | | 59,381 | |
| Nuclear fuel purchases | | | (557,960 | ) | | | (641,493 | ) | | | (407,711 | ) |
| Payment for purchase of plant | | | (456,356 | ) | | | (646,137 | ) | | | - | |
| Proceeds from sale of assets and businesses | | | - | | | | 6,531 | | | | 228,171 | |
| Insurance proceeds received for property damages | | | - | | | | - | | | | 7,894 | |
| Changes in securitization account | | | 4,265 | | | | (7,260 | ) | | | (29,945 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | (72,000 | ) |
| Payments to storm reserve escrow account | | | (8,957 | ) | | | (6,425 | ) | | | (296,614 | ) |
| Receipts from storm reserve escrow account | | | 27,884 | | | | - | | | | 9,925 | |
| Decrease (increase) in other investments | | | 15,175 | | | | (11,623 | ) | | | 24,956 | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 109,105 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,074,055 | | | | 1,360,346 | | | | 2,606,383 | |
| Investment in nuclear decommissioning trust funds | | | (2,196,489 | ) | | | (1,475,017 | ) | | | (2,730,377 | ) |
| Net cash flow used in investing activities | | | (3,639,797 | ) | | | (3,446,853 | ) | | | (2,574,223 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | |
| Long-term debt | | | 3,478,361 | | | | 2,990,881 | | | | 3,870,694 | |
| Mandatorily redeemable preferred membership units of subsidiary | | | 51,000 | | | | - | | | | - | |
| Treasury stock | | | 62,886 | | | | 46,185 | | | | 51,163 | |
| Retirement of long-term debt | | | (3,130,233 | ) | | | (2,437,372 | ) | | | (4,178,127 | ) |
| Repurchase of common stock | | | - | | | | (234,632 | ) | | | (878,576 | ) |
| Redemption of subsidiary common and preferred stock | | | - | | | | (30,308 | ) | | | - | |
| Changes in credit borrowings and commercial paper - net | | | 687,675 | | | | (6,501 | ) | | | (8,512 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (589,209 | ) | | | (589,605 | ) | | | (603,854 | ) |
| Preferred stock | | | (22,329 | ) | | | (20,933 | ) | | | (20,063 | ) |
| Net cash flow provided by (used in) financing activities | | | 538,151 | | | | (282,285 | ) | | | (1,767,275 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (508 | ) | | | 287 | | | | 338 | |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (161,869 | ) | | | (600,034 | ) | | | (415,079 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 694,438 | | | | 1,294,472 | | | | 1,709,551 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 532,569 | | | $ | 694,438 | | | $ | 1,294,472 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 546,125 | | | $ | 532,271 | | | $ | 534,004 | |
| Income taxes | | $ | 49,214 | | | $ | (2,042 | ) | | $ | 32,144 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 112,992 | | | $ | 81,468 | |
| Temporary cash investments | | | 419,577 | | | | 612,970 | |
| Total cash and cash equivalents | | | 532,569 | | | | 694,438 | |
| Securitization recovery trust account | | | 46,040 | | | | 50,304 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 568,871 | | | | 568,558 | |
| Allowance for doubtful accounts | | | (31,956 | ) | | | (31,159 | ) |
| Other | | | 161,408 | | | | 166,186 | |
| Accrued unbilled revenues | | | 303,392 | | | | 298,283 | |
| Total accounts receivable | | | 1,001,715 | | | | 1,001,868 | |
| Deferred fuel costs | | | 150,363 | | | | 209,776 | |
| Accumulated deferred income taxes | | | 306,902 | | | | 9,856 | |
| Fuel inventory - at average cost | | | 213,831 | | | | 202,132 | |
| Materials and supplies - at average cost | | | 928,530 | | | | 894,756 | |
| Deferred nuclear refueling outage costs | | | 243,374 | | | | 231,031 | |
| System agreement cost equalization | | | 16,880 | | | | 36,800 | |
| Prepayments and other | | | 242,922 | | | | 291,742 | |
| TOTAL | | | 3,683,126 | | | | 3,622,703 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 46,738 | | | | 44,876 | |
| Decommissioning trust funds | | | 4,190,108 | | | | 3,788,031 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 256,039 | | | | 260,436 | |
| Other | | | 436,234 | | | | 416,423 | |
| TOTAL | | | 4,929,119 | | | | 4,509,766 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 41,944,567 | | | | 39,385,524 | |
| Property under capital lease | | | 935,199 | | | | 809,449 | |
| Natural gas | | | 353,492 | | | | 343,550 | |
| Construction work in progress | | | 1,365,699 | | | | 1,779,723 | |
| Nuclear fuel | | | 1,598,430 | | | | 1,546,167 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 46,197,387 | | | | 43,864,413 | |
| Less - accumulated depreciation and amortization | | | 18,898,842 | | | | 18,255,128 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 27,298,545 | | | | 25,609,285 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 742,030 | | | | 799,006 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $914,751 as of December 31, 2012 and $1,009,103 as of | | | | | | | | |
| December 31, 2011) | | | 5,025,912 | | | | 4,636,871 | |
| Deferred fuel costs | | | 172,202 | | | | 172,202 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Accumulated deferred income taxes | | | 37,748 | | | | 19,003 | |
| Other | | | 936,648 | | | | 955,691 | |
| TOTAL | | | 7,291,712 | | | | 6,959,945 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 718,516 | | | $ | 2,192,733 | |
| Notes payable and commercial paper | | | 796,002 | | | | 108,331 | |
| Accounts payable | | | 1,217,180 | | | | 1,069,096 | |
| Customer deposits | | | 359,078 | | | | 351,741 | |
| Taxes accrued | | | 333,719 | | | | 278,235 | |
| Accumulated deferred income taxes | | | 13,109 | | | | 99,929 | |
| Interest accrued | | | 184,664 | | | | 183,512 | |
| Deferred fuel costs | | | 96,439 | | | | 255,839 | |
| Obligations under capital leases | | | 3,880 | | | | 3,631 | |
| Pension and other postretirement liabilities | | | 95,900 | | | | 44,031 | |
| System agreement cost equalization | | | 25,848 | | | | 80,090 | |
| Other | | | 261,986 | | | | 283,531 | |
| TOTAL | | | 4,106,321 | | | | 4,950,699 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 8,311,756 | | | | 8,096,452 | |
| Accumulated deferred investment tax credits | | | 273,696 | | | | 284,747 | |
| Obligations under capital leases | | | 34,541 | | | | 38,421 | |
| Other regulatory liabilities | | | 898,614 | | | | 728,193 | |
| Decommissioning and asset retirement cost liabilities | | | 3,513,634 | | | | 3,296,570 | |
| Accumulated provisions | | | 362,226 | | | | 385,512 | |
| Pension and other postretirement liabilities | | | 3,725,886 | | | | 3,133,657 | |
| Long-term debt (includes securitization bonds of $973,480 as of | | | | | | | | |
| December 31, 2012 and $1,070,556 as of December 31, 2011) | | | 11,920,318 | | | | 10,043,713 | |
| Other | | | 577,910 | | | | 501,954 | |
| TOTAL | | | 29,618,581 | | | | 26,509,219 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 186,511 | | | | 186,511 | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2012 and in 2011 | | | 2,548 | | | | 2,548 | |
| Paid-in capital | | | 5,357,852 | | | | 5,360,682 | |
| Retained earnings | | | 9,704,591 | | | | 9,446,960 | |
| Accumulated other comprehensive loss | | | (293,083 | ) | | | (168,452 | ) |
| Less - treasury stock, at cost (76,945,239 shares in 2012 and | | | | | | | | |
| 78,396,988 shares in 2011) | | | 5,574,819 | | | | 5,680,468 | |
| Total common shareholders' equity | | | 9,197,089 | | | | 8,961,270 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 9,291,089 | | | | 9,055,270 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 43,202,502 | | | $ | 40,701,699 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Common Shareholders’ Equity | | | | |
| | | Subsidiaries’ Preferred Stock | | | Common Stock | | | Treasury Stock | | | Paid-in Capital | | | Retained Earnings | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 94,000 | | | $ | 2,548 | | | $ | (4,727,167 | ) | | $ | 5,370,042 | | | $ | 8,043,122 | | | $ | (75,185 | ) | | $ | 8,707,360 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,063 | | | | - | | | | - | | | | - | | | | 1,250,242 | | | | - | | | | 1,270,305 | |
| Other comprehensive income | | | - | | | | - | | | | - | | | | - | | | | - | | | | 36,973 | | | | 36,973 | |
| Common stock repurchases | | | - | | | | - | | | | (878,576 | ) | | | - | | | | - | | | | - | | | | (878,576 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 80,932 | | | | (2,568 | ) | | | - | | | | - | | | | 78,364 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (603,963 | ) | | | - | | | | (603,963 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,063 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,063 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2010 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,524,811 | ) | | $ | 5,367,474 | | | $ | 8,689,401 | | | $ | (38,212 | ) | | $ | 8,590,400 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 20,933 | | | | - | | | | - | | | | - | | | | 1,346,439 | | | | - | | | | 1,367,372 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (130,240 | ) | | | (130,240 | ) |
| Common stock repurchases | | | - | | | | - | | | | (234,632 | ) | | | - | | | | - | | | | - | | | | (234,632 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | | 78,975 | | | | (6,792 | ) | | | - | | | | - | | | | 72,183 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (588,880 | ) | | | - | | | | (588,880 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (20,933 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (20,933 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2011 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,680,468 | ) | | $ | 5,360,682 | | | $ | 9,446,960 | | | $ | (168,452 | ) | | $ | 9,055,270 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | | | 21,690 | | | | - | | | | - | | | | - | | | | 846,673 | | | | - | | | | 868,363 | |
| Other comprehensive loss | | | - | | | | - | | | | - | | | | - | | | | - | | | | (124,631 | ) | | | (124,631 | ) |
| Common stock issuances related to stock plans | | | - | | | | - | | | $ | 105,649 | | | | (2,830 | ) | | | - | | | | - | | | | 102,819 | |
| Common stock dividends declared | | | - | | | | - | | | | - | | | | - | | | | (589,042 | ) | | | - | | | | (589,042 | ) |
| Preferred dividend requirements of subsidiaries (a) | | | (21,690 | ) | | | - | | | | - | | | | - | | | | - | | | | - | | | | (21,690 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2012 | | $ | 94,000 | | | $ | 2,548 | | | $ | (5,574,819 | ) | | $ | 5,357,852 | | | $ | 9,704,591 | | | $ | (293,083 | ) | | $ | 9,291,089 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | �� | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2012, 2011, and 2010 include $15.0 million, $13.3 million, and $13.3 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF INCOME |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands, Except Share Data) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 7,880,016 | | | $ | 10,073,160 | | | $ | 9,046,301 | |
| Natural gas | | | 172,213 | | | | 241,856 | | | | 206,073 | |
| Competitive businesses | | | 2,693,421 | | | | 2,778,740 | | | | 2,232,024 | |
| TOTAL | | | 10,745,650 | | | | 13,093,756 | | | | 11,484,398 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operating and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 2,309,831 | | | | 3,577,764 | | | | 2,934,833 | |
| Purchased power | | | 1,395,203 | | | | 2,491,200 | | | | 1,986,950 | |
| Nuclear refueling outage expenses | | | 241,310 | | | | 221,759 | | | | 180,971 | |
| Other operation and maintenance | | | 2,750,810 | | | | 2,742,762 | | | | 2,649,654 | |
| Decommissioning | | | 199,063 | | | | 189,409 | | | | 167,898 | |
| Taxes other than income taxes | | | 503,859 | | | | 496,952 | | | | 489,058 | |
| Depreciation and amortization | | | 1,082,775 | | | | 1,030,860 | | | | 963,712 | |
| Other regulatory charges (credits) - net | | | (21,727 | ) | | | 59,883 | | | | 54,954 | |
| TOTAL | | | 8,461,124 | | | | 10,810,589 | | | | 9,428,030 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 2,284,526 | | | | 2,283,167 | | | | 2,056,368 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 59,545 | | | | 44,523 | | | | 42,742 | |
| Interest and dividend income | | | 236,628 | | | | 197,872 | | | | 238,911 | |
| Other than temporary impairment losses | | | (86,069 | ) | | | (49,656 | ) | | | (4,914 | ) |
| Equity in earnings (loss) of unconsolidated equity affiliates | | | (7,793 | ) | | | (11,684 | ) | | | 3,176 | |
| Miscellaneous - net | | | (32,603 | ) | | | (11,768 | ) | | | (24,860 | ) |
| TOTAL | | | 169,708 | | | | 169,287 | | | | 255,055 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 520,716 | | | | 500,898 | | | | 506,089 | |
| Other interest - net | | | 82,963 | | | | 133,290 | | | | 155,995 | |
| Allowance for borrowed funds used during construction | | | (33,235 | ) | | | (25,267 | ) | | | (25,032 | ) |
| TOTAL | | | 570,444 | | | | 608,921 | | | | 637,052 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 1,883,790 | | | | 1,843,533 | | | | 1,674,371 | |
| | | | | | | | | | | | | |
| Income taxes | | | 632,740 | | | | 602,998 | | | | 514,417 | |
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME | | | 1,251,050 | | | | 1,240,535 | | | | 1,159,954 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | | 19,958 | | | | 19,969 | | | | 25,105 | |
| | | | | | | | | | | | | |
| NET INCOME ATTRIBUTABLE TO ENTERGY CORPORATION | | $ | 1,231,092 | | | $ | 1,220,566 | | | $ | 1,134,849 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| Earnings per average common share: | | | | | | | | | | | | |
| Basic | | $ | 6.39 | | | $ | 6.39 | | | $ | 5.77 | |
| Diluted | | $ | 6.30 | | | $ | 6.20 | | | $ | 5.60 | |
| Dividends declared per common share | | $ | 3.00 | | | $ | 3.00 | | | $ | 2.58 | |
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | | 192,772,032 | | | | 190,925,613 | | | | 196,572,945 | |
| Diluted average number of common shares outstanding | | | 195,838,068 | | | | 201,011,588 | | | | 202,780,283 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Consolidated net income | | $ | 1,251,050 | | | $ | 1,240,535 | | | $ | 1,159,954 | |
| Adjustments to reconcile consolidated net income to net cash flow | | | | | | | | | | | | |
| provided by operating activities: | | | | | | | | | | | | |
| Reserve for regulatory adjustments | | | (508 | ) | | | (8,285 | ) | | | (15,574 | ) |
| Other regulatory charges (credits) - net | | | (21,727 | ) | | | 59,883 | | | | 54,954 | |
| Depreciation, amortization, and decommissioning | | | 1,281,838 | | | | 1,220,269 | | | | 1,131,610 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 864,684 | | | | 333,948 | | | | 476,241 | |
| Equity in losses of unconsolidated equity affiliates - net of dividends | | | 7,793 | | | | 11,684 | | | | (3,176 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 116,444 | | | | 78,653 | | | | (62,646 | ) |
| Fuel inventory | | | 19,291 | | | | (7,561 | ) | | | (10,445 | ) |
| Accounts payable | | | (14,251 | ) | | | (23,225 | ) | | | (103,048 | ) |
| Taxes accrued | | | (75,210 | ) | | | 75,210 | | | | (187,324 | ) |
| Interest accrued | | | 4,974 | | | | (652 | ) | | | 11,785 | |
| Deferred fuel | | | 72,314 | | | | (38,500 | ) | | | 912 | |
| Other working capital accounts | | | (228,210 | ) | | | (72,372 | ) | | | (73,269 | ) |
| Provision for estimated losses and reserves | | | (12,030 | ) | | | 12,462 | | | | (59,292 | ) |
| Changes in other regulatory assets | | | (415,157 | ) | | | (324,211 | ) | | | 254,736 | |
| Changes in pensions and other postretirement liabilities | | | 71,789 | | | | 828,160 | | | | (56,224 | ) |
| Other | | | 10,074 | | | | (61,670 | ) | | | 40,576 | |
| Net cash flow provided by operating activities | | | 2,933,158 | | | | 3,324,328 | | | | 2,559,770 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction/capital expenditures | | | (1,931,245 | ) | | | (2,212,255 | ) | | | (1,578,030 | ) |
| Allowance for equity funds used during construction | | | 59,545 | | | | 44,523 | | | | 42,742 | |
| Nuclear fuel purchases | | | (525,474 | ) | | | (423,951 | ) | | | (408,732 | ) |
| Proceeds from sale/leaseback of nuclear fuel | | | 284,997 | | | | 297,097 | | | | 169,066 | |
| Proceeds from sale of assets and businesses | | | 39,554 | | | | 30,725 | | | | 13,063 | |
| Payment for purchase of plant | | | - | | | | (266,823 | ) | | | (336,211 | ) |
| Insurance proceeds received for property damages | | | 53,760 | | | | 130,114 | | | | 83,104 | |
| Changes in transition charge account | | | (1,036 | ) | | | 7,211 | | | | (19,273 | ) |
| NYPA value sharing payment | | | (72,000 | ) | | | (72,000 | ) | | | - | |
| Increase (decrease) in other investments | | | 94,154 | | | | (72,833 | ) | | | 41,720 | |
| Proceeds from nuclear decommissioning trust fund sales | | | 2,570,523 | | | | 1,652,277 | | | | 1,583,584 | |
| Investment in nuclear decommissioning trust funds | | | (2,667,172 | ) | | | (1,704,181 | ) | | | (1,708,764 | ) |
| Net cash flow used in investing activities | | | (2,094,394 | ) | | | (2,590,096 | ) | | | (2,117,731 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | | 2009 | | | | 2008 | | | | 2007 | |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | | | | |
| Long-term debt | | | 2,003,469 | | | | 3,456,695 | | | | 2,866,136 | |
| Preferred equity | | | - | | | | - | | | | 10,000 | |
| Common stock and treasury stock | | | 28,198 | | | | 34,775 | | | | 78,830 | |
| Retirement of long-term debt | | | (1,843,169 | ) | | | (2,486,806 | ) | | | (1,369,945 | ) |
| Repurchase of common stock | | | (613,125 | ) | | | (512,351 | ) | | | (1,215,578 | ) |
| Redemption of preferred stock | | | (1,847 | ) | | | - | | | | (57,827 | ) |
| Changes in short term borrowings - net | | | (25,000 | ) | | | 30,000 | | | | - | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (576,956 | ) | | | (573,045 | ) | | | (507,327 | ) |
| Preferred stock | | | (19,958 | ) | | | (20,025 | ) | | | (25,875 | ) |
| Net cash flow used in financing activities | | | (1,048,388 | ) | | | (70,757 | ) | | | (221,586 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | | (1,316 | ) | | | 3,288 | | | | 30 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (210,940 | ) | | | 666,763 | | | | 220,483 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 1,920,491 | | | | 1,253,728 | | | | 1,016,152 | |
| | | | | | | | | | | | | |
| Effect of the reconsolidation of Entergy New Orleans on cash and cash equivalents | | | - | | | | - | | | | 17,093 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 1,709,551 | | | $ | 1,920,491 | | | $ | 1,253,728 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 568,417 | | | $ | 612,288 | | | $ | 611,197 | |
| Income taxes | | $ | 43,057 | | | $ | 137,234 | | | $ | 376,808 | |
| | | | | | | | | | | | | |
| Noncash financing activities: | | | | | | | | | | | | |
| Long-term debt retired (equity unit notes) | | $ | (500,000 | ) | | | - | | | | - | |
| Common stock issued in settlement of equity unit purchase contracts | | $ | 500,000 | | | | - | | | | - | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | | | | | |
| | | December 31, |
| | | 2009 | | | 2008 | |
| | | (In Thousands) |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 85,861 | | | $ | 115,876 | |
| Temporary cash investments | | | 1,623,690 | | | | 1,804,615 | |
| Total cash and cash equivalents | | | 1,709,551 | | | | 1,920,491 | |
| Securitization recovery trust account | | | 13,098 | | | | 12,062 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 553,692 | | | | 734,204 | |
| Allowance for doubtful accounts | | | (27,631 | ) | | | (25,610 | ) |
| Other | | | 152,303 | | | | 206,627 | |
| Accrued unbilled revenues | | | 302,463 | | | | 282,914 | |
| Total accounts receivable | | | 980,827 | | | | 1,198,135 | |
| Deferred fuel costs | | | 126,798 | | | | 167,092 | |
| Accumulated deferred income taxes | | | - | | | | 7,307 | |
| Fuel inventory - at average cost | | | 196,855 | | | | 216,145 | |
| Materials and supplies - at average cost | | | 825,702 | | | | 776,170 | |
| Deferred nuclear refueling outage costs | | | 225,290 | | | | 221,803 | |
| System agreement cost equalization | | | 70,000 | | | | 394,000 | |
| Prepayments and other | | | 386,040 | | | | 247,184 | |
| TOTAL | | | 4,534,161 | | | | 5,160,389 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 39,580 | | | | 66,247 | |
| Decommissioning trust funds | | | 3,211,183 | | | | 2,832,243 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 247,664 | | | | 231,115 | |
| Other | | | 120,273 | | | | 107,939 | |
| TOTAL | | | 3,618,700 | | | | 3,237,544 | |
| | | | | | | | | |
| PROPERTY, PLANT AND EQUIPMENT | | | | | | | | |
| Electric | | | 36,343,772 | | | | 34,495,406 | |
| Property under capital lease | | | 783,096 | | | | 745,504 | |
| Natural gas | | | 314,256 | | | | 303,769 | |
| Construction work in progress | | | 1,547,319 | | | | 1,712,761 | |
| Nuclear fuel under capital lease | | | 527,521 | | | | 465,374 | |
| Nuclear fuel | | | 739,827 | | | | 636,813 | |
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | | 40,255,791 | | | | 38,359,627 | |
| Less - accumulated depreciation and amortization | | | 16,866,389 | | | | 15,930,513 | |
| PROPERTY, PLANT AND EQUIPMENT - NET | | | 23,389,402 | | | | 22,429,114 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 619,500 | | | | 581,719 | |
| Other regulatory assets | | | 3,647,154 | | | | 3,615,104 | |
| Deferred fuel costs | | | 172,202 | | | | 168,122 | |
| Goodwill | | | 377,172 | | | | 377,172 | |
| Other | | | 1,006,306 | | | | 1,047,654 | |
| TOTAL | | | 5,822,334 | | | | 5,789,771 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 37,364,597 | | | $ | 36,616,818 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| | | | | | | | | |
| | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | | | | | | | |
| | | December 31, |
| | | | 2009 | | | | 2008 | |
| | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | | $ | 711,957 | | | $ | 544,460 | |
| Notes payable | | | 30,031 | | | | 55,034 | |
| Accounts payable | | | 998,228 | | | | 1,475,745 | |
| Customer deposits | | | 323,342 | | | | 302,303 | |
| Taxes accrued | | | - | | | | 75,210 | |
| Accumulated deferred income taxes | | | 48,584 | | | | - | |
| Interest accrued | | | 192,283 | | | | 187,310 | |
| Deferred fuel costs | | | 219,639 | | | | 183,539 | |
| Obligations under capital leases | | | 212,496 | | | | 162,393 | |
| Pension and other postretirement liabilities | | | 55,031 | | | | 46,288 | |
| System agreement cost equalization | | | 187,204 | | | | 460,315 | |
| Other | | | 215,202 | | | | 273,297 | |
| TOTAL | | | 3,193,997 | | | | 3,765,894 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 7,422,319 | | | | 6,565,770 | |
| Accumulated deferred investment tax credits | | | 308,395 | | | | 325,570 | |
| Obligations under capital leases | | | 354,233 | | | | 343,093 | |
| Other regulatory liabilities | | | 421,985 | | | | 280,643 | |
| Decommissioning and asset retirement cost liabilities | | | 2,939,539 | | | | 2,677,495 | |
| Accumulated provisions | | | 141,315 | | | | 147,452 | |
| Pension and other postretirement liabilities | | | 2,241,039 | | | | 2,177,993 | |
| Long-term debt | | | 10,705,738 | | | | 11,174,289 | |
| Other | | | 711,334 | | | | 880,998 | |
| TOTAL | | | 25,245,897 | | | | 24,573,303 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Subsidiaries' preferred stock without sinking fund | | | 217,343 | | | | 217,029 | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Common Shareholders' Equity: | | | | | | | | |
| Common stock, $.01 par value, authorized 500,000,000 shares; | | | | | | | | |
| issued 254,752,788 shares in 2009 and 248,174,087 shares in 2008 | | | 2,548 | | | | 2,482 | |
| Paid-in capital | | | 5,370,042 | | | | 4,869,303 | |
| Retained earnings | | | 8,043,122 | | | | 7,382,719 | |
| Accumulated other comprehensive loss | | | (75,185 | ) | | | (112,698 | ) |
| Less - treasury stock, at cost (65,634,580 shares in 2009 and | | | | | | | | |
| 58,815,518 shares in 2008) | | | 4,727,167 | | | | 4,175,214 | |
| Total common shareholders' equity | | | 8,613,360 | | | | 7,966,592 | |
| Subsidiaries' preferred stock without sinking fund | | | 94,000 | | | | 94,000 | |
| TOTAL | | | 8,707,360 | | | | 8,060,592 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 37,364,597 | | | $ | 36,616,818 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF RETAINED EARNINGS, COMPREHENSIVE INCOME, AND PAID-IN CAPITAL |
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | |
| RETAINED EARNINGS | | | | | | | | | | | | | | | | | | |
| Retained Earnings - Beginning of period | | $ | 7,382,719 | | | | | | $ | 6,735,965 | | | | | | $ | 6,113,042 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | | | | | | | | | | |
| Net income attributable to Entergy Corporation | | | 1,231,092 | | | $ | 1,231,092 | | | | 1,220,566 | | | $ | 1,220,566 | | | | 1,134,849 | | | $ | 1,134,849 | |
| Adjustments related to implementation of new accounting pronouncements | | | 6,365 | | | | | | | | - | | | | | | | | (4,600 | ) | | | | |
| Total | | | 1,237,457 | | | | | | | | 1,220,566 | | | | | | | | 1,130,249 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividends declared on common stock | | | 576,913 | | | | | | | | 573,924 | | | | | | | | 507,326 | | | | | |
| Capital stock and other expenses | | | 141 | | | | | | | | (112 | ) | | | | | | | - | | | | | |
| Total | | | 577,054 | | | | | | | | 573,812 | | | | | | | | 507,326 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Retained Earnings - End of period | | $ | 8,043,122 | | | | | | | $ | 7,382,719 | | | | | | | $ | 6,735,965 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS) | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated derivative instrument fair value changes | | $ | 120,830 | | | | | | | $ | (12,540 | ) | | | | | | $ | (105,578 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | | (232,232 | ) | | | | | | | (107,145 | ) | | | | | | | (105,909 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized investment gains | | | (4,402 | ) | | | | | | | 121,611 | | | | | | | | 104,551 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Foreign currency translation | | | 3,106 | | | | | | | | 6,394 | | | | | | | | 6,424 | | | | | |
| Total | | | (112,698 | ) | | | | | | | 8,320 | | | | | | | | (100,512 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net derivative instrument fair value changes | | | | | | | | | | | | | | | | | | | | | | | | |
| arising during the period (net of tax expense of $333, $78,837 and $57,185) | | | (2,887 | ) | | | (2,887 | ) | | | 133,370 | | | | 133,370 | | | | 93,038 | | | | 93,038 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Pension and other postretirement liabilities (net of tax expense (benefit) of ($34,415), ($68,076) and $29,994) | | | (35,707 | ) | | | (35,707 | ) | | | (125,087 | ) | | | (125,087 | ) | | | (1,236 | ) | | | (1,236 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Net unrealized investment gains (net of tax expense (benefit) of $102,845, ($108,049) and $23,562) | | | 82,929 | | | | 82,929 | | | | (126,013 | ) | | | (126,013 | ) | | | 17,060 | | | | 17,060 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Adjustment related to implementation of new accounting pronouncement (net of tax benefit of ($4,921)) | | | (6,365 | ) | | | - | | | | - | | | | - | | | | - | | | | - | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Foreign currency translation (net of tax benefit of ($246), ($1,770) and ($16)) | | | (457 | ) | | | (457 | ) | | | (3,288 | ) | | | (3,288 | ) | | | (30 | ) | | | (30 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at end of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated derivative instrument fair value changes | | | 117,943 | | | | | | | | 120,830 | | | | | | | | (12,540 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | | (267,939 | ) | | | | | | | (232,232 | ) | | | | | | | (107,145 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Net unrealized investment gains | | | 72,162 | | | | | | | | (4,402 | ) | | | | | | | 121,611 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Foreign currency translation | | | 2,649 | | | | | | | | 3,106 | | | | | | | | 6,394 | | | | | |
| Total | | $ | (75,185 | ) | | | | | | $ | (112,698 | ) | | | | | | $ | 8,320 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Add: preferred dividend requirements of subsidiaries | | | | | | | 19,958 | | | | | | | | 19,969 | | | | | | | | 25,105 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Comprehensive Income | | | | | | $ | 1,294,928 | | | | | | | $ | 1,119,517 | | | | | | | $ | 1,268,786 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| PAID-IN CAPITAL | | | | | | | | | | | | | | | | | | | | | | | | |
| Paid-in Capital - Beginning of period | | $ | 4,869,303 | | | | | | | $ | 4,850,769 | | | | | | | $ | 4,827,265 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | | | | | | | | | | | | | |
| Common stock issuances in settlement of equity unit purchase contracts | | | 499,934 | | | | | | | | - | | | | | | | | - | | | | | |
| Common stock issuances related to stock plans | | | 805 | | | | | | | | 18,534 | | | | | | | | 23,504 | | | | | |
| Total | | | 500,739 | | | | | | | | 18,534 | | | | | | | | 23,504 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Paid-in Capital - End of period | | $ | 5,370,042 | | | | | | | $ | 4,869,303 | | | | | | | $ | 4,850,769 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The accompanying consolidated financial statements include the accounts of Entergy Corporation and its subsidiaries. As required by generally accepted accounting principles in the United States of America, all significant intercompany transactions have been eliminated in the consolidated financial statements. Entergy'sEntergy’s Registrant Subsidiaries (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy) also include their separate financial statements in this Form 10-K. The Registrant Subsidiaries and many other Entergy subsidiaries maintain accounts in accordance with FERC and other regulatory guidelines. Certain previously reportedpreviously-reported amounts have been reclassified to conform to current classifications, with no effect on net income or shareholders'common shareholders’ (or members'members’) equity.
Use of Estimates in the Preparation of Financial Statements
In conformity with generally accepted accounting principles in the United States of America, the preparation of Entergy Corporation'sCorporation’s consolidated financial statements and the separate financial statements of the Registrant Subsidiaries requires management to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues, and expenses and the disclosure of contingent assets and liabilities. Adjustments to the reported amounts of assets and liabilities may be necessary in the future to the extent that future estimates or actual results are different from the estimates used.
Revenues and Fuel Costs
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Louisiana, Mississippi, and Texas, respectively. Entergy Gulf States Louisiana also distributes natural gas to retail customers in and around Baton Rouge, Louisiana. Entergy New Orleans sells both electric power and natural gas to retail customers in the City of New Orleans, except for Algiers, where Entergy Louisiana is the electric power supplier. Entergy's Non-Utility NuclearThe Entergy Wholesale Commodities segment derives almost all of its revenue from sales of electric power generated by plants owned by the Non-Utility Nuclearsubsidiaries in that segment.
Entergy recognizes revenue from electric power and natural gas sales when power or gas is delivered to customers. To the extent that deliveries have occurred but a bill has not been issued, Entergy'sEntergy’s Utility operating companies accrue an estimate of the revenues for energy delivered since the latest billings. The Utility operating companies calculate the estimate based upon several factors including billings through the last billing cycle in a month, actual generation in the month, historical line loss factors, and prices in effect in Entergy'sEntergy’s Utility operating companies'companies’ various jurisdictions. Changes are made to the inputs in the estimate as needed to reflect changes in billing practices. Each month the estimated unbilled revenue amounts are recorded as revenue and unbilled accounts receivable, and the prior month'smonth’s estimate is reversed. Therefore, changes in price and volume differences resulting from factors such as weather affect the calculation of unbilled revenues from one period to the next, and may result in variability in reported revenues from one period to the next as prior estimates are reversed and new estimates recorded.
Entergy'sEntergy records revenue from sales under rates implemented subject to refund less estimated amounts accrued for probable refunds when Entergy believes it is probable that revenues will be refunded to customers based upon the status of the rate proceeding as of the date the financial statements are prepared.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Utility operating companies'companies’ rate schedules include either fuel adjustment clauses or fixed fuel factors, which allow either current recovery in billings to customers or deferral of fuel costs until the costs are billed to customers. Where the fuel component of revenues is billed based on a pre-determined fuel cost (fixed fuel factor), the fuel factor remains in effect until changed as part of a general rate case, fuel reconciliation, or fixed fuel factor filing.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy'sfiling.System Energy’s operating revenues are intended to recover from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans operating expenses and capital costs attributable to Grand Gulf. The capital costs are computed by allowing a return on System Energy'sEnergy’s common equity funds allocable to its net investment in Grand Gulf, plus System Energy'sEnergy’s effective interest cost for its debt allocable to its investment in Grand Gulf.
Property, Plant, and Equipment
Property, plant, and equipment is stated at original cost. Depreciation is computed on the straight-line basis at rates based on the applicable estimated service lives of the various classes of property. For the Registrant Subsidiaries, the original cost of plant retired or removed, less salvage, is charged to accumulated depreciation. Normal maintenance, repairs, and minor replacement costs are charged to operating expenses. Substantially all of the Registrant Subsidiaries'Subsidiaries’ plant is subject to mortgage liens.
Electric plant includes the portions of Grand Gulf and Waterford 3 that have been sold and leased back. For financial reporting purposes, these sale and leaseback arrangements are reflected as financing transactions.
Net property, plant, and equipment for Entergy (including property under capital lease and associated accumulated amortization) by business segment and functional category, as of December 31, 20092012 and 2008,2011, is shown below:
2009 | | Entergy | | Utility | | Non-Utility Nuclear | | All Other | |
2012 | | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $8,105 | | $5,414 | | $2,691 | | $- | | $ | 9,588 | | | $ | 6,624 | | | $ | 2,964 | | | $ | - | |
Other | | 1,724 | | 1,724 | | - | | - | | | 2,878 | | | | 2,493 | | | | 385 | | | | - | |
| Transmission | | 2,922 | | 2,889 | | 33 | | - | | | 3,654 | | | | 3,619 | | | | 35 | | | | - | |
| Distribution | | 5,948 | | 5,948 | | - | | - | | | 6,561 | | | | 6,561 | | | | - | | | | - | |
| Other | | 1,876 | | 1,398 | | 255 | | 223 | | | 1,654 | | | | 1,416 | | | | 235 | | | | 3 | |
| Construction work in progress | | 1,547 | | 1,134 | | 412 | | 1 | | | 1,366 | | | | 973 | | | | 392 | | | | 1 | |
| Nuclear fuel (leased and owned) | | 1,267 | | 747 | | 520 | | - | |
| Nuclear fuel | | | | 1,598 | | | | 907 | | | | 691 | | | | - | |
| Property, plant, and equipment - net | | $23,389 | | $19,254 | | $3,911 | | $224 | | $ | 27,299 | | | $ | 22,593 | | | $ | 4,702 | | | $ | 4 | |
2008 | | Entergy | | Utility | | Non-Utility Nuclear | | All Other |
| | | (In Millions) |
| Production | | | | | | | | |
Nuclear | | $7,998 | | $5,468 | | $2,530 | | $- |
Other | | 1,944 | | 1,723 | | - | | 221 |
| Transmission | | 2,757 | | 2,724 | | 33 | | - |
| Distribution | | 5,361 | | 5,361 | | - | | - |
| Other | | 1,554 | | 1,283 | | 271 | | - |
| Construction work in progress | | 1,713 | | 1,441 | | 252 | | 20 |
| Nuclear fuel (leased and owned) | | 1,102 | | 596 | | 506 | | - |
| Property, plant, and equipment - net | | $22,429 | | $18,596 | | $3,592 | | $241 |
Depreciation rates on average depreciable property for Entergy approximated 2.7% in 2009, 2008, and 2007. Included in these rates are the depreciation rates on average depreciable utility property of 2.7% in 2009, 2.7% in 2008, and 2.6% in 2007 and the depreciation rates on average depreciable non-utility property of 3.8% in 2009, 3.7% in 2008, and 3.6% in 2007.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
" 2011 | | Entergy | | | Utility | | | Entergy Wholesale Commodities | | | Parent & Other | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | |
Nuclear | | $ | 8,635 | | | $ | 5,441 | | | $ | 3,194 | | | $ | - | |
Other | | | 2,431 | | | | 2,032 | | | | 399 | | | | - | |
| Transmission | | | 3,344 | | | | 3,309 | | | | 35 | | | | - | |
| Distribution | | | 6,157 | | | | 6,157 | | | | - | | | | - | |
| Other | | | 1,716 | | | | 1,463 | | | | 250 | | | | 3 | |
| Construction work in progress | | | 1,780 | | | | 1,420 | | | | 359 | | | | 1 | |
| Nuclear fuel | | | 1,546 | | | | 802 | | | | 744 | | | | - | |
| Property, plant, and equipment - net | | $ | 25,609 | | | $ | 20,624 | | | $ | 4,981 | | | $ | 4 | |
Depreciation rates on average depreciable property for Entergy approximated 2.5% in 2012, 2.6% in 2011, and 2.6% in 2010. Included in these rates are the depreciation rates on average depreciable Utility property of 2.4% in 2012, 2.5% in 2011, and 2.5% 2010, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 3.5% in 2012, 3.9% in 2011, and 3.7% in 2010.
Entergy amortizes nuclear fuel using a units-of-production method. Nuclear fuel amortization is included in fuel expense in the income statements.
“Non-utility property - at cost (less accumulated depreciation)"” for Entergy is reported net of accumulated depreciation of $197.8$230.4 million and $185.8$214.3 million as of December 31, 20092012 and 2008,2011, respectively.
Construction expenditures included in accounts payable is $267 million and $171 million at December 31, 2009 is $159.8 million.2012 and 2011, respectively.
Net property, plant, and equipment for the Registrant Subsidiaries (including property under capital lease and associated accumulated amortization) by company and functional category, as of December 31, 20092012 and 2008,2011, is shown below:
2009 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
2012 | | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $1,017 | | $1,484 | | $1,450 | | $- | | $- | | $- | | $1,463 | | $ | 1,073 | | | $ | 1,428 | | | $ | 2,180 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,943 | |
Other | | 414 | | 300 | | 384 | | 331 | | (6) | | 301 | | - | | | 621 | | | | 286 | | | | 680 | | | | 545 | | | | (11 | ) | | | 371 | | | | - | |
| Transmission | | 819 | | 416 | | 611 | | 467 | | 27 | | 543 | | 6 | | | 1,034 | | | | 573 | | | | 734 | | | | 581 | | | | 27 | | | | 642 | | | | 28 | |
| Distribution | | 1,618 | | 870 | | 1,330 | | 943 | | 280 | | 907 | | - | | | 1,747 | | | | 939 | | | | 1,454 | | | | 1,065 | | | | 331 | | | | 1,025 | | | | - | |
| Other | | 202 | | 185 | | 307 | | 220 | | 174 | | 113 | | 21 | | | 115 | | | | 187 | | | | 289 | | | | 201 | | | | 182 | | | | 106 | | | | 17 | |
| Construction work in progress | | 115 | | 84 | | 510 | | 63 | | 21 | | 82 | | 199 | | | 206 | | | | 125 | | | | 405 | | | | 63 | | | | 11 | | | | 90 | | | | 40 | |
| Nuclear fuel (leased and owned) | | 185 | | 163 | | 122 | | - | | - | | - | | 85 | |
| Nuclear fuel | | | | 304 | | | | 147 | | | | 204 | | | | - | | | | - | | | | - | | | | 253 | |
| Property, plant, and equipment - net | | $4,370 | | $3,502 | | $4,714 | | $2,024 | | $496 | | $1,946 | | $1,774 | | $ | 5,100 | | | $ | 3,685 | | | $ | 5,946 | | | $ | 2,455 | | | $ | 540 | | | $ | 2,234 | | | $ | 2,281 | |
2008 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| Production | | | | | | | | | | | | | | |
Nuclear | | $1,063 | | $1,410 | | $1,434 | | $- | | $- | | $- | | $1,561 |
Other | | 470 | | 239 | | 354 | | 346 | | - | | 314 | | - |
| Transmission | | 782 | | 386 | | 508 | | 476 | | 21 | | 545 | | 6 |
| Distribution | | 1,519 | | 733 | | 1,148 | | 885 | | 236 | | 840 | | - |
| Other | | 201 | | 180 | | 302 | | 194 | | 165 | | 110 | | 20 |
| Construction work in progress | | 142 | | 202 | | 602 | | 82 | | 22 | | 221 | | 123 |
| Nuclear fuel (leased and owned) | | 137 | | 152 | | 74 | | - | | - | | - | | 133 |
| Property, plant, and equipment - net | | $4,314 | | $3,302 | | $4,422 | | $1,983 | | $444 | | $2,030 | | $1,843 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Millions) | |
| Production | | | | | | | | | | | | | | | | | | | | | |
Nuclear | | $ | 1,034 | | | $ | 1,458 | | | $ | 1,561 | | | $ | - | | | $ | - | | | $ | - | | | $ | 1,388 | |
Other | | | 398 | | | | 286 | | | | 679 | | | | 350 | | | | (7 | ) | | | 325 | | | | - | |
| Transmission | | | 942 | | | | 500 | | | | 706 | | | | 510 | | | | 22 | | | | 624 | | | | 5 | |
| Distribution | | | 1,700 | | | | 856 | | | | 1,304 | | | | 1,009 | | | | 298 | | | | 990 | | | | - | |
| Other | | | 173 | | | | 192 | | | | 278 | | | | 206 | | | | 186 | | | | 110 | | | | 18 | |
| Construction work in progress | | | 120 | | | | 122 | | | | 559 | | | | 105 | | | | 14 | | | | 91 | | | | 358 | |
| Nuclear fuel | | | 273 | | | | 206 | | | | 165 | | | | - | | | | - | | | | - | | | | 158 | |
| Property, plant, and equipment - net | | $ | 4,640 | | | $ | 3,620 | | | $ | 5,252 | | | $ | 2,180 | | | $ | 513 | | | $ | 2,140 | | | $ | 1,927 | |
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2009 | | 3.3% | | 1.9% | | 2.5% | | 2.6% | | 3.0% | | 2.3% | | 2.9% |
| 2008 | | 3.2% | | 2.2% | | 2.5% | | 2.6% | | 3.1% | | 2.4% | | 2.9% |
| 2007 | | 3.2% | | 2.2% | | 2.5% | | 2.5% | | 3.0% | | 2.4% | | 2.8% |
| | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2012 | | 2.5% | | 1.8% | | 2.4% | | 2.6% | | 3.0% | | 2.4% | | 2.8% |
| 2011 | | 2.6% | | 1.8% | | 2.5% | | 2.6% | | 3.0% | | 2.2% | | 2.8% |
| 2010 | | 2.9% | | 1.8% | | 2.4% | | 2.6% | | 3.1% | | 2.3% | | 2.9% |
Non-utility property - at cost (less accumulated depreciation) for Entergy Gulf States Louisiana is reported net of accumulated depreciation of $131$142 million and $126.2$136 million as of December 31, 20092012 and 2008,2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $2.3$2.8 million and $2.1$2.7 million as of December 31, 20092012 and 2008,2011, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $9.2$10 million and $9$9.8 million as of December 31, 20092012 and 2008,2011, respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As of December 31, 2009,2012, construction expenditures included in accounts payable are $13.2$56.3 million for Entergy Arkansas, $7.6$9.7 million for Entergy Gulf States Louisiana, $26.0$110.4 million for Entergy Louisiana, $3.0$4.8 million for Entergy Mississippi, $22 thousand$1.9 million for Entergy New Orleans, $4.4$8.6 million for Entergy Texas, and $15.7$13.5 million for System Energy. As of December 31, 2011, construction expenditures included in accounts payable are $14.1 million for Entergy Arkansas, $13.7 million for Entergy Gulf States Louisiana, $27 million for Entergy Louisiana, $4.3 million for Entergy Mississippi, $3.6 million for Entergy New Orleans, $4.3 million for Entergy Texas, and $32.9 million for System Energy.
System Energy has invested, through its subsidiary Entergy New Nuclear Development, LLC, in initial development costs for potential new nuclear development at the Grand Gulf and River Bend sites, including licensing and design activities. As of December 31, 2009, $100.3 million in construction work in progress was recorded on System Energy's balance sheet related to this project. In the first quarter 2010, $24.9 million, $24.9 million, and $49.5 million of this construction work in progress was transferred to Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Mississippi, respectively.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. The investments and expenses associated with these generating stations are recorded by the Entergy subsidiaries to the extent of their respective undivided ownership interests. As of December 31, 2009,2012, the subsidiaries'subsidiaries’ investment and accumulated depreciation in each of these generating stations were as follows:
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $91 |
| | Common Facilities | | Coal | | | | | | | | |
White Bluff | Units 1 and 2 | | Coal | | 1,640 | | 57.00% | | $486 | | $323 |
| Ouachita (3) | Common Facilities | | Gas | | | | | | | | |
| Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 550 | | 40.25% | | $236 | | $162 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $141 | | $89 |
| Ouachita (3) | Common Facilities | | Gas | | | | | | | | |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | | | | | | | |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 550 | | 29.75% | | $173 | | $115 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $105 | | $66 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,210 | | 90.00%(2) | | $3,806 | | $2,315 |
| | | | | | | | | | | | |
| Non-nuclear wholesale assets: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $74 | | $39 |
| | Common Facilities | | Coal | | | | 7.18% | | | | |
| Harrison County | | | Gas | | 550 | | 60.90% | | $207 | | $29 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Generating Stations | | Fuel-Type | | Total Megawatt Capability (1) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | |
Independence | Unit 1 | | Coal | | 836 | | 31.50% | | $128 | | $86 |
| | Common Facilities | | Coal | | | | 15.75% | | $33 | | $22 |
White Bluff | Units 1 and 2 | | Coal | | 1,659 | | 57.00% | | $498 | | $319 |
Ouachita (2) | Common Facilities | | Gas | | | | 66.67% | | $169 | | $142 |
Entergy Gulf States Louisiana - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 40.25% | | $250 | | $170 |
Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 15.92% | | $9 | | $3 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 24.15% | | $142 | | $99 |
Ouachita (2) | Common Facilities | | Gas | | | | 33.33% | | $87 | | $73 |
| Entergy Louisiana - | | | | | | | | | | | |
| Acadia | Common Facilities | | Gas | | | | 50.00% | | $8 | | $- |
| Entergy Mississippi - | | | | | | | | | | | |
Independence | Units 1 and 2 and Common Facilities | | Coal | | 1,678 | | 25.00% | | $250 | | $140 |
| Entergy Texas - | | | | | | | | | | | |
Roy S. Nelson | Unit 6 | | Coal | | 540 | | 29.75% | | $180 | | $113 |
Roy S. Nelson | Unit 6 Common
Facilities | | Coal | | | | 11.77% | | $6 | | $2 |
Big Cajun 2 | Unit 3 | | Coal | | 588 | | 17.85% | | $107 | | $68 |
| System Energy - | | | | | | | | | | | |
Grand Gulf | Unit 1 | | Nuclear | | 1,430(4) | | 90.00%(3) | | $4,557 | | $2,569 |
| | | | | | | | | | | | |
Entergy Wholesale Commodities: | | | | | | | | | | | |
| Independence | Unit 2 | | Coal | | 842 | | 14.37% | | $69 | | $43 |
| Independence | Common
Facilities | | Coal | | | | 7.18% | | $16 | | $9 |
| Roy S. Nelson | Unit 6 | | Coal | | 540 | | 10.9% | | $104 | | $54 |
| Roy S. Nelson | Unit 6 Common Facilities | | Coal | | | | 4.31% | | $2 | | $1 |
| | | | | | | | | | | | |
| (1) | "“Total Megawatt Capability"Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Includes an 11.5% leasehold interest held by System Energy. System Energy's Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
(3) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Gulf States Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities.facilities and not for the generating units. |
| (3) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
| (4) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Nuclear Refueling Outage Costs
Nuclear refueling outage costs are deferred during the outage and amortized over the estimated period to the next outage because these refueling outage expenses are incurred to prepare the units to operate for the next operating cycle without having to be taken off line.
Allowance for Funds Used During Construction (AFUDC)
AFUDC represents the approximate net composite interest cost of borrowed funds and a reasonable return on the equity funds used for construction by the Registrant Subsidiaries. AFUDC increases both the plant balance and earnings and is realized in cash through depreciation provisions included in rates.the rates charged to customers.
Income Taxes
Entergy Corporation and the majority of its subsidiaries file a United States consolidated federal income tax return. Each tax payingtax-paying entity records income taxes as if it were a separate taxpayer and consolidating adjustments are allocated to the tax filing entities in accordance with Entergy'sEntergy’s intercompany income tax allocation agreement. Deferred income taxes are recorded for all temporary differences between the book and tax basis of assets and liabilities, and for certain credits available for carryforward. Entergy Louisiana, formed December 31, 2005, was not a member of the consolidated group in 2006 and 2007 and filed a separate federal income tax return. Beginning January 1, 2008, Entergy Louisiana joined the Entergy consolidated federal income tax return.
Deferred tax assets are reduced by a valuation allowance when, in the opinion of management, it is more likely than not that some portion of the deferred tax assets will not be realized. Deferred tax assets and liabilities are adjusted for the effects of changes in tax laws and rates in the period in which the tax or rate was enacted.
Investment tax credits are deferred and amortized based upon the average useful life of the related property, in accordance with ratemaking treatment.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Earnings per Share
The following table presents Entergy'sEntergy’s basic and diluted earnings per share calculation included on the consolidated statements of income:
| | For the Years Ended December 31, |
| | 2009 | 2008 | 2007 |
| | | (In Millions, Except Per Share Data) |
| Basic earnings per average common share | Income | Shares | | $/share | Income | Shares | | $/share | Income | Shares | | $/share |
Net income attributable to Entergy Corporation | $1,231.1 | 192.8 | | $6.39 | $1,220.6 | 190.9 | | $6.39 | $1,134.8 | 196.6 | | $5.77 |
| Average dilutive effect of: | | | | | | | | | | | | |
Stock options | - | 2.2 | | (0.07) | - | 4.1 | | (0.13) | - | 5.0 | | (0.14) |
Equity units | 3.2 | 0.8 | | (0.02) | 24.7 | 6.0 | | (0.06) | - | 1.1 | | (0.03) |
Deferred units | - | - | | - | - | - | | - | - | 0.1 | | - |
Diluted earnings per average common share | $1,234.3 | 195.8 | | $6.30 | $1,245.3 | 201.0 | | $6.20 | $1,134.8 | 202.8 | | $5.60 |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Millions, Except Per Share Data) | |
| | | | | | $/share | | | | | | $/share | | | | | | $/share | |
| Net income attributable to Entergy Corporation | | $ | 846.7 | | | | | | $ | 1,346.4 | | | | | | $ | 1,250.2 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Basic earnings per average common share | | | 177.3 | | | $ | 4.77 | | | | 177.4 | | | $ | 7.59 | | | | 186.0 | | | $ | 6.72 | |
| Average dilutive effect of: | | | | | | | | | | | | | | | | | | | | | | | | |
Stock options | | | 0.3 | | | | (0.01 | ) | | | 1.0 | | | | (0.04 | ) | | | 1.8 | | | | (0.06 | ) |
Other equity plans | | | 0.1 | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Diluted earnings per average common shares | | | 177.7 | | | $ | 4.76 | | | | 178.4 | | | $ | 7.55 | | | | 187.8 | | | $ | 6.66 | |
The calculation of diluted earnings per share excluded 4,368,6147,164,319 options outstanding at December 31, 20092012, 5,712,604 options outstanding at December 31, 2011, and 5,380,262 options outstanding at December 31, 2010 that could potentially dilute basic earnings per share in the future. Those options were not included in the calculation of diluted earnings per share because the exercise price of those options exceeded the average market price for the year. As of December 31, 2008, the calculation of diluted earnings per share excluded 3,326,835 options because the exercise price of those options exceeded the average market price for the year. All options to purchase common stock shares in 2007 were included in the computation of diluted earnings per share because the common share average market price at the end of 2007 was greater than the exercise prices of all of the options outstanding.
Entergy Corporation was unableand Subsidiaries
Notes to remarket successfully $500 million of notes associated with its equity units. The note holders therefore put the notes to Entergy, Entergy retired the notes, and Entergy issued 6,598,000 shares of common stock to the note holders.Financial Statements
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted liability awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans, which isare shareholder-approved stock-based compensation plans. These plans are described more fully in Note 12 to the financial statements. Effective January 1, 2003, Entergy prospectively adoptedThe cost of the fair value based method of accounting for stock options.stock-based compensation is charged to income over the vesting period. Awards under Entergy'sEntergy’s plans generally vest over three years. Stock-based compensation expense included in consolidated net income, net of related tax effects, for 2009 is $10.4 million, for 2008 is $10.7 million, and for 2007 is $8.9 million for Entergy's stock options granted.
Accounting for the Effects of Regulation
Entergy'sEntergy’s Utility operating companies and System Energy are rate-regulated enterprises whose rates meet three criteria specified in accounting standards. The Utility operating companies and System Energy have rates that (i) are approved by a body (its regulator) empowered to set rates that bind customers (its regulator);customers; (ii) are cost-based; and (iii) can be charged to and collected from customers. These criteria may also be applied to separable portions of a utility'sutility’s business, such as the generation or transmission functions, or to specific classes of customers. Because the Utility operating companies and System Energy meet these criteria, each of them capitalizes costs that would otherwise be charged to expense if the rate actions
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of its regulator make it probable that those costs will be recovered in future revenue. Such capitalized costs are reflected as regulatory assets in the accompanying financial statements. When an enterprise concludes that recovery of a regulatory asset is no longer probable, the regulatory asset must be removed from the entity'sentity’s balance sheet.
An enterprise that ceases to meet the three criteria for all or part of its operations should report that event in its financial statements. In general, the enterprise no longer meeting the criteria should eliminate from its balance sheet all regulatory assets and liabilities related to the applicable operations. Additionally, if it is determined that a regulated enterprise is no longer recovering all of its costs, it is possible that an impairment may exist that could require further write-offs of plant assets.
Entergy Gulf States Louisiana does not apply regulatory accounting standards to the Louisiana retail deregulated portion of River Bend, the 30% interest in River Bend formerly owned by Cajun, and its steam business.business, where specific recovery is not provided for in tariff rates. The Louisiana retail deregulated portion of River Bend is operated under a deregulated asset plan representing a portion (approximately 15%) of River Bend plant costs, generation, revenues, and expenses established under a 1992 LPSC order. The plan allows Entergy Gulf States Louisiana to sell the electricity from the deregulated assets to Louisiana retail customers at 4.6 cents per kWh or off-system at higher prices, with certain provisions for sharing incremental revenue above 4.6 cents per kWh between ratepayers and shareholders.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at date of purchase to be cash equivalents.
Allowance for Doubtful Accounts
The allowance for doubtful accounts reflects Entergy’s best estimate of losses on the accounts receivable balances. The allowance is based on accounts receivable agings, historical experience, and other currently available evidence. Utility operating company customer accounts receivable are written off consistent with approved regulatory requirements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Investments
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend that is not rate-regulated, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders' equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders' equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Effective January 1, 2009, Entergy adopted an accounting pronouncement providing guidance regarding recognition and presentation of other-than-temporary impairments related to investments in debt securities. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to beis based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy'sEntergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. See Note 17 to the financial statements for details on the decommissioning trust funds and the other than temporary impairments recorded in 2009 and 2008.funds.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Equity Method InvesteesInvestments
Entergy owns investments that are accounted for under the equity method of accounting because Entergy'sEntergy’s ownership level results in significant influence, but not control, over the investee and its operations. Entergy records its share of earnings or losses of the investee based on the change during the period in the estimated liquidation value of the investment, assuming that the investee'sinvestee’s assets were to be liquidated at book value. In accordance with this method, earnings are allocated to owners or members based on what each partner would receive from its capital account if, hypothetically, liquidation were to occur at the balance sheet date and amounts distributed were based on recorded book values. Entergy discontinues the recognition of losses on equity investments when its share of losses equals or exceeds its carrying amount for an investee plus any advances made or commitments to provide additional financial support. See Note 14 to the financial statements for additional information regarding Entergy'sEntergy’s equity method investments.
Derivative Financial Instruments and Commodity Derivatives
The accounting standards for derivative instruments and hedging activities require that all derivatives be recognized at fair value on the balance sheet, either as assets or liabilities, unless they meet various exceptions including the normal purchase, normal sales criteria. The changes in the fair value of recognized derivatives are recorded each period in current earnings or other comprehensive income, depending on whether a derivative is designated as part of a hedge transaction and the type of hedge transaction.
Contracts for commodities that will be physically delivered in quantities expected to be used or sold in the ordinary course of business, including certain purchases and sales of power and fuel, meet the normal purchase, normal sales criteria and are not recognized on the balance sheet. Revenues and expenses from these contracts are reported on a gross basis in the appropriate revenue and expense categories as the commodities are received or delivered.
For other contracts for commodities in which Entergy is hedging the variability of cash flows related to a variable-rate asset, liability, or forecasted transactions that qualify as cash flow hedges, the changes in the fair value of such derivative instruments are reported in other comprehensive income. To qualify for hedge accounting, the relationship between the hedging instrument and the hedged item must be documented to include the risk management objective and strategy and, at inception and on an ongoing basis, the effectiveness of the hedge in offsetting the changes in the cash flows of the item being hedged. Gains or losses accumulated in other comprehensive income are reclassified asto earnings in the periods in which earnings are affected bywhen the variability of the cash flows of the hedged item.underlying transactions actually occur. The ineffective portions of all hedges are recognized in current-period earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has determined that contracts to purchase uranium do not meet the definition of a derivative under the accounting standards for derivative instruments because they do not provide for net settlement and the uranium markets are not sufficiently liquid to conclude that forward contracts are readily convertible to cash. If the uranium markets do become sufficiently liquid in the future and Entergy begins to account for uranium purchase contracts as derivative instruments, the fair value of these contracts would be accounted for consistent with Entergy'sEntergy’s other derivative instruments.
Fair Values
The estimated fair values of Entergy'sEntergy’s financial instruments and derivatives are determined using bid prices and market quotes. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments held by regulated businesses may be reflected in future rates and therefore do not accrue to the benefit or detriment of stockholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments. See Note 16 to the financial statements for further discussion of fair value.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Impairment of Long-Lived Assets
Entergy periodically reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets.
Two nuclear power plants in the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have applications pending for renewed NRC licenses. Various parties have expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their license expiration dates while their renewal applications are pending NRC approval. If the NRC does not renew the operating license for any of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and impairing its value as an asset.
In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years. The renewed operating license expires in March 2032. In May 2011 the Vermont Department of Public Service and the New England Coalition petitioned the United States Court of Appeals for the D.C. Circuit seeking judicial review of the NRC’s issuance of the renewed operating license, alleging that the license had been issued without a valid and effective water quality certification under Section 401 of the Clean Water Act. Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. intervened in the proceeding. In June 2012 the Court of Appeals denied the appeal on the ground that the petitioners had failed to exhaust their administrative remedies before the NRC. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired.
Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that was scheduled to expire in March 2012, but has an application pending before the Vermont Public Service Board (VPSB) for a new Certificate of Public Good for operation until March 2032. In April 2011, Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, the owner and operator respectively of Vermont Yankee, filed suit in the United States District Court for the District of Vermont. The suit challenged certain conditions imposed by Vermont upon Vermont Yankee’s continued operation and storage of spent nuclear fuel, including the requirement to obtain not only a new Certificate of Public Good, but also approval by Vermont’s General Assembly. In January 2012 the court entered judgment in Entergy’s favor and specifically:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| · | Declared that Vermont’s laws requiring Vermont Yankee to cease operation in March 2012 and prohibiting the storage of spent nuclear fuel from operation after that date, absent approval by the General Assembly, were based on radiological safety concerns and are preempted by the Atomic Energy Act; |
| · | Permanently enjoined Vermont from enforcing these preempted requirements of the state’s laws; and |
| · | Permanently enjoined Vermont under the Commerce Clause of the United States Constitution from conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states. |
In February 2012 the Vermont defendants appealed the decision to the United States Court of Appeals for the Second Circuit. Vermont Yankee cross-appealed on two grounds: (1) the Federal Power Act alternatively preempts conditioning the issuance of a new Certificate of Public Good upon the existence of a below wholesale market power sale agreement with Vermont utilities or Vermont Yankee’s selling power to Vermont utilities at rates below those available to wholesale customers in other states (an issue the District Court found unnecessary to decide in light of its ruling under the Commerce Clause); and (2) a request to make permanent the injunction pending appeal that the District Court entered on March 19, 2012 which prohibits Vermont from enforcing a statutory provision to compel Vermont Yankee to shut down because the cumulative total amount of spent fuel stored at the site exceeds the amount derived from the operation of the facility up to, but not beyond, March 21, 2012 (a provision the enforcement of which the January 2012 decision had not enjoined). The appeal and cross-appeal remain pending.
In January 2012, Entergy filed a motion requesting that the VPSB grant, based on the existing record in its proceeding, Vermont Yankee’s pending application for a new Certificate of Public Good. Entergy subsequently filed another motion asking the VPSB to declare that title 3, section 814(b) of the Vermont statutes (3 V.S.A. § 814(b)) authorized Vermont Yankee to operate while the Certificate of Public Good proceeding was pending because Entergy had timely filed a petition for a new Certificate of Public Good that had not yet been decided. In March 2012 the VPSB issued orders denying Entergy’s motion with respect to 3 V.S.A. § 814(b) but stating that the order did not require Vermont Yankee to cease operations, denying Entergy’s motion to issue a new Certificate of Public Good based on the existing record, determining to open a new docket and to create a new record to decide Vermont Yankee’s request for a new Certificate of Public Good (without prejudice to any rights that Entergy might have under 3 V.S.A. § 814(b)), and directing Entergy to file an amended Certificate of Public Good petition that identified the specific approvals it was seeking in light of the district court’s decision. In April 2012, Entergy filed its amended Certificate of Public Good petition and in June 2012 filed its initial testimony in support of that petition. The VPSB’s current schedule provides for hearings and briefs to be filed through August 2013, but no date for a decision by the VPSB.
In May 2012, Entergy filed a motion asking the VPSB to amend the 2002 and 2006 VPSB orders respectively approving Entergy’s acquisition of Vermont Yankee and Vermont Yankee’s construction of a spent nuclear fuel storage facility. These orders contained conditions respectively precluding the operation of Vermont Yankee after March 21, 2012 absent issuance of a new or renewed certificate of public good and limiting the amount of spent nuclear fuel stored at the site, in each case without explicitly addressing whether those conditions were subject to 3 V.S.A. § 814(b). In its March 2012 order the VPSB had found 3 V.S.A. § 814(b) did not apply to the conditions in those orders even though it did apply to the certificates of public good issued by the orders. In November 2012 the VPSB denied Entergy’s motion to amend the 2002 and 2006 VPSB orders. In December 2012 the Conservation Law Foundation filed a complaint in the Vermont Supreme Court, based on the VPSB’s November order, which sought an order shutting down Vermont Yankee while its Certificate of Public Good application is pending. Entergy moved to dismiss that complaint on the basis, among other grounds, that 3 V.S.A. § 814(b) allows Vermont Yankee to operate while its Certificate of Public Good application is being decided. The Vermont Supreme Court heard oral argument on the motion in January 2013. Also in January 2013, the VPSB issued an order closing the old Certificate of Public Good docket (the one superseded by Entergy’s April 2012 amended petition) in which the VPSB’s March 2012 and November 2012 orders had been issued, making an appeal from those orders ripe. Entergy immediately filed a notice appealing those VPSB orders to the Vermont Supreme Court. Entergy expects to file its appeal brief in March 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2012, Entergy filed a petition asking the VPSB to issue a Certificate of Public Good allowing construction at Vermont Yankee for a diesel generator to provide power in the event of a station blackout. Vermont Yankee currently can obtain such power from the Vernon Dam. Due to changes instituted by ISO-New England, Vermont Yankee will no longer be able to rely upon the Vernon Dam in the event of a station blackout after August 31, 2013 and therefore plans to install a new diesel generator as a replacement power source. The VPSB requested and received comments on Entergy’s September 2012 petition and its relationship to Entergy’s other petition for a Certificate of Public Good. In December 2012 the VPSB issued an order opening an investigation into Vermont Yankee’s Certificate of Public Good diesel generator application. In February 2013 the VPSB issued a notice allowing comments to be filed by March 15, 2013, but not otherwise establishing a schedule for completing that investigation.
Impairment
Because of the uncertainty regarding the continued operation of Vermont Yankee, Entergy has tested the recoverability of the plant and related assets each quarter since the first quarter 2010. The determination of recoverability is based on the probability-weighted undiscounted net cash flows expected to be generated by the plant and related assets. Projected net cash flows primarily depend on the status of the pending legal and state regulatory matters, as well as projections of future revenues and expenses over the remaining life of the plant. Prior to the first quarter 2012, the probability-weighted undiscounted net cash flows exceeded the carrying value of the Vermont Yankee plant and related assets. The decline, however, in the overall energy market and the projected forward prices of power as of March 31, 2012, which are significant inputs in the determination of net cash flows, resulted in the probability-weighted undiscounted future cash flows being less than the asset group’s carrying value. Entergy performed a fair value analysis based on the income approach, a discounted cash flow method, to determine the amount of impairment. The estimated fair value of the plant and related assets at March 31, 2012 was $162.0 million, while the carrying value was $517.5 million. Therefore, the assets were written down to their fair value and an impairment charge of $355.5 million ($223.5 million after-tax) was recognized. The impairment charge is recorded as a separate line item in Entergy’s consolidated statement of income for 2012, and is included within the results of the Entergy Wholesale Commodities segment.
The estimate of fair value was based on the price that Entergy would expect to receive in a hypothetical sale of the Vermont Yankee plant and related assets to a market participant on March 31, 2012. In order to determine this price, Entergy used significant observable inputs, including quoted forward power and gas prices, where available. Significant unobservable inputs, such as projected long-term pre-tax operating margins (cash basis), and estimated weighted average costs of capital were also used in the estimation of fair value. In addition, Entergy made certain assumptions regarding future tax deductions associated with the plant and related assets. Based on the use of significant unobservable inputs, the fair value measurement for the entirety of the asset group, and for each type of asset within the asset group, is classified as Level 3 in the fair value hierarchy discussed in Note 16 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the Vermont Yankee plant and related assets as of March 31, 2012:
Significant Unobservable Inputs | Range | Weighted
Average |
| | |
| Weighted average cost of capital | 7.5%-8.0% | 7.8% |
| Long-term pre-tax operating margin (cash basis) | 6.1%-7.8% | 7.2% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the Vermont Yankee plant and related assets, in consultation with external advisors. Accounting Policy obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair value of the asset group.
River Bend AFUDC
The River Bend AFUDC gross-up is a regulatory asset that represents the incremental difference imputed by the LPSC between the AFUDC actually recorded by Entergy Gulf States Louisiana on a net-of-tax basis during the construction of River Bend and what the AFUDC would have been on a pre-tax basis. The imputed amount was only calculated on that portion of River Bend that the LPSC allowed in rate base and is being amortized through August 2025.
Reacquired Debt
The premiums and costs associated with reacquired debt of Entergy'sEntergy’s Utility operating companies and System Energy (except that portion allocable to the deregulated operations of Entergy Gulf States Louisiana) are included in regulatory assets and are being amortized over the life of the related new issuances, or over the life of the original debt issuance if the debt is not refinanced, in accordance with ratemaking treatment.
Taxes Imposed on Revenue-Producing Transactions
Governmental authorities assess taxes that are both imposed on and concurrent with a specific revenue-producing transaction between a seller and a customer, including, but not limited to, sales, use, value added, and some excise taxes. Entergy presents these taxes on a net basis, excluding them from revenues, unless required to report them differently by a regulatory authority.
Presentation of Non-Controlling Interests
In 2007, a new accounting pronouncement was issued regarding non-controlling interests that requires generally that ownership interests in subsidiaries held by parties other than the reporting company (non-controlling interests) be clearly identified, labeled, and presented in the consolidated balance sheet within equity, but separate from the controlling shareholders' equity, and that the amount of consolidated net income attributable to the reporting company and to the non-controlling interests be clearly identified and presented on the face of the consolidated income statement. This new accounting pronouncement became effective for Entergy in the first quarter 2009 and applies to preferred securities issued by Entergy subsidiaries to third parties.
Presentation of Preferred Stock without Sinking Fund
In connection with the adoption of the new accounting pronouncementAccounting standards regarding non-controlling interests Entergy evaluated the accounting standards regardingand the classification and measurement of redeemable securities. These standardssecurities require the classification of preferred securities between liabilities and shareholders'shareholders’ equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company'scompany’s preferred securities may elect a majority of the respective company'scompany’s board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders'shareholders’ equity on the balance sheet. Entergy Gulf States Louisiana and Entergy Louisiana, both organized as limited liability companies, have outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provide for the election of board members that would not constitute a majority of the board; and their preferred securities are therefore classified for all periods presented as a component of members'members’ equity.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Asset Management whose(whose preferred holders also havehad protective rights as describeduntil the securities were repurchased in Note 6 to the financial statements,December 2011), are similarly presented between liabilities and shareholders' equity on Entergy'sEntergy’s consolidated balance sheets and the outstanding preferred securities of Entergy Gulf States Louisiana and Entergy Louisiana are presented within total equity in Entergy'sEntergy’s consolidated balance sheets. The preferred dividends or distributions paid by all subsidiaries are reflected for all periods presented outside of consolidated net income.
Subsequent Events
Entergy evaluated events of which its management was aware subsequent to December 31, 2009, through the date that this annual report was issued.
New Accounting Pronouncements
In June 2009 the FASB issued SFAS 167, "Amendments to FASB Interpretation No. 46R". SFAS 167 replaces the current quantitative-based risks and rewards calculation for determining which enterprise, if any, has a controlling financial interest in a variable interest entity with an approach focused on identifying which enterprise has the power to direct the activities of a variable interest entity that most significantly affect the entity's economic performance and (1) the obligation to absorb losses of the entity or (2) the right to receive benefits from the entity. SFAS 167 also requires additional disclosures on an interim and annual basis about an enterprise's involvement in variable interest entities. The standard will be effective for Entergy in the first quarter 2010. Upon adoption, Entergy expects its subsidiaries that finance their nuclear fuel purchases through nuclear fuel leases to consolidate the special purpose nuclear fuel companies acting as lessors. The adoption of this statement will result in the reclassification of amounts between certain line items in the financial statements.
Entergy Gulf States Louisiana and Entergy Texas Basis of Presentation
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.'s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Because the jurisdictional separation was a transaction involving entities under common control, Entergy Texas recognized the assets and liabilities allocated to it at their carrying amounts in the accounts of Entergy Gulf States, Inc. at the time of the jurisdictional separation. Entergy Texas' financial statements report results of operations for 2007 as though the jurisdictional separation had occurred at the beginning of 2007, and presented its 2007 balance sheet as though the assets and liabilities had been allocated at December 31, 2007. Financial information presented for prior periods has also been presented on that basis to furnish comparative information.
As the successor to Entergy Gulf States, Inc. for financial reporting purposes, Entergy Gulf States Louisiana's income statement and cash flow statement for the year ended December 31, 2007 include the operations of Entergy Texas.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
New Accounting Pronouncements
The accounting standard-setting process, including projects between the FASB and the International Accounting Standards Board (IASB) to converge U.S. GAAP and International Financial Reporting Standards, is ongoing and the FASB and the IASB are each currently working on several projects that have not yet resulted in final pronouncements. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets
Other Regulatory Assets
Regulatory assets represent probable future revenues associated with costs that are expected to be recovered from customers through the regulatory ratemaking process affecting the Utility business. In addition to the regulatory assets that are specifically disclosed on the face of the balance sheets, the tabletables below providesprovide detail of "Other“Other regulatory assets"assets” that are included on Entergy'sEntergy’s and the Registrant Subsidiaries'Subsidiaries’ balance sheets as of December 31, 20092012 and 2008:2011:
Entergy
| | | 2009 | | 2008 |
| | | (In Millions) |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $403.9 | | $371.2 |
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | 23.2 | | 48.4 |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 Fuel and purchased power cost recovery) | | 58.2 | | 28.6 |
Gas hedging costs - recovered through fuel rates | | 0.4 | | 66.8 |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non Qualified Pension Plans) (b) | | 1,481.7 | | 1,468.6 |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | 7.2 | | 9.6 |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | 44.4 | | 63.9 |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | 28.1 | | 29.9 |
Sale-leaseback deferral - Grand Gulf and Waterford 3 Lease Obligations recovered through June 2014 and December 2044, respectively (Note 10 – Sale and Leaseback Transactions – Grand Gulf Lease Obligations and Waterford 3 Lease Obligations) | | 115.3 | | 122.8 |
Spindletop gas storage facility - recovered through December 2032 (a) | | 34.2 | | 35.8 |
Transition to competition - recovered through February 2021 (Note 2 – Retail Rate Proceedings – Filings with the PUCT and Texas Cities) | | 101.9 | | 107.6 |
Unamortized loss on reacquired debt - recovered over term of debt | | 115.0 | | 124.0 |
| Unrealized loss on decommissioning trust funds | | - | | 42.3 |
| Other | | 50.5 | | 54.2 |
Total | | $3,647.2 | | $3,615.1 |
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 422.6 | | | $ | 395.9 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | 6.8 | | | | - | |
Grand Gulf fuel - non-current and power management rider - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | 35.1 | | | | 12.4 | |
New nuclear generation development costs (Note 2) | | | 56.8 | | | | 56.8 | |
Gas hedging costs - recovered through fuel rates | | | 8.3 | | | | 30.3 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | | 2,866.3 | | | | 2,542.0 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | | - | | | | 2.4 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 – Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 970.8 | | | | 996.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | | 155.7 | | | | 81.2 | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | | 29.4 | | | | 31.0 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | 82.1 | | | | 89.2 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Incremental ice storm costs - recovered through 2032 | | | 10.0 | | | | 10.5 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | 11.0 | | | | 12.9 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 95.9 | | | | 108.8 | |
| Other | | | 75.1 | | | | 44.4 | |
Total | | $ | 5,025.9 | | | $ | 4,636.9 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $179.4 | | $164.9 | | $ | 210.2 | | | $ | 187.7 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | - | | 5.9 | |
Incremental ice storm costs - recovered through 2032 | | 11.6 | | 12.1 | | | 10.0 | | | | 10.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | 447.6 | | 441.6 | | | 831.2 | | | | 768.3 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | 8.2 | | 19.4 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | | 17.3 | | | | 4.6 | |
Postretirement benefits - recovered through 2012 (Note 11 – Other Postretirement Benefits) (b) | | 7.2 | | 9.6 | | | - | | | | 2.4 | |
Provision for storm damages - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | 61.7 | | - | | | 115.2 | | | | 114.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 29.7 | | 32.3 | | | 31.5 | | | | 34.7 | |
| Other | | 1.6 | | 3.2 | | | 6.2 | | | | 4.0 | |
Entergy Arkansas Total | | $747.0 | | $689.0 | | $ | 1,221.6 | | | $ | 1,126.9 | |
Entergy Gulf States Louisiana
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $17.6 | | $15.0 | | $ | 6.1 | | | $ | 12.8 | |
Gas hedging costs - recovered through fuel rates | | 0.3 | | 20.2 | | | 2.6 | | | | 8.6 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | 142.7 | | 121.2 | | | 300.5 | | | | 231.3 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | | | |
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | 15.7 | | 13.6 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | | 18.9 | | | | 10.2 | |
Deferred capacity (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | | | 6.8 | | | | - | |
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | | 28.1 | | 29.9 | | | 22.4 | | | | 24.3 | |
Spindletop gas storage facility - recovered through December 2032 (a) | | 34.2 | | 35.8 | | | 29.4 | | | | 31.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 14.1 | | 15.2 | | | 9.9 | | | | 11.6 | |
| Other | | 3.3 | | 4.7 | | | 13.1 | | | | 4.1 | |
Entergy Gulf States Louisiana Total | | $299.8 | | $287.9 | | $ | 409.7 | | | $ | 333.9 | |
Entergy Louisiana
| | | 2009 | | 2008 |
| | | (In Millions) |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $99.9 | | $86.2 |
FRP deferral - recovery to be determined in formula rate plan proceeding | | - | | 17.5 |
Gas hedging costs - recovered through fuel rates | | - | | 26.7 |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | 200.4 | | 196.8 |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | | |
Deferred capacity - recovery timing will be determined by the LPSC in the formula rate plan filings (Note 2 – Retail Rate Proceedings – Filings with the LPSC) | | 7.5 | | 32.3 |
Sale-leaseback deferral - recovered through December 2044 (Note 10 – Sale and Leaseback Transactions – Waterford 3 Lease Obligations ) | | 40.7 | | 31.8 |
Unamortized loss on reacquired debt - recovered over term of debt | | 19.7 | | 21.7 |
| Other | | 17.2 | | 21.7 |
Entergy Louisiana Total | | $477.0 | | $515.1 |
| | | 2012 | | | 2011 | |
| | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $ | 136.9 | | | $ | 125.8 | |
Gas hedging costs - recovered through fuel rates | | | 3.4 | | | | 12.4 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) | | | 475.6 | | | | 427.9 | |
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | | | 177.6 | | | | 198.4 | |
Provision for storm damages, including hurricane costs - recovered through retail rates and securitization (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | 74.5 | | | | 9.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | | 17.6 | | | | 20.0 | |
| Other | | | 28.0 | | | | 20.3 | |
Entergy Louisiana Total | | $ | 913.6 | | | $ | 814.5 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $4.7 | | $4.5 | | $ | 5.6 | | | $ | 5.3 | |
Gas hedging costs - recovered through fuel rates | | | | 2.2 | | | | 7.8 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | 44.5 | | 40.0 | | | 57.4 | | | | 48.5 | |
Grand Gulf fuel - non-current - recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | 50.0 | | 9.3 | |
Gas hedging costs - recovered through fuel rates | | - | | 15.6 | |
Grand Gulf fuel - non-current and power management rider- recovered through rate riders when rates are redetermined periodically (Note 2 – Fuel and purchased power cost recovery) | | | | 17.8 | | | | 7.8 | |
New nuclear generation development costs (Note 2) | | | | 56.8 | | | | 56.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | 131.5 | | 136.3 | | | 234.6 | | | | 221.1 | |
Provision for storm damages - recovered through retail rates | | 10.0 | | 9.3 | | | 9.2 | | | | 30.7 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 10.1 | | 11.3 | | | 9.6 | | | | 10.7 | |
| Other | | 0.6 | | 0.6 | | | 8.3 | | | | 4.7 | |
Entergy Mississippi Total | | $251.4 | | $226.9 | | $ | 401.5 | | | $ | 393.4 | |
Entergy New Orleans
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $3.0 | | $2.8 | | $ | 3.6 | | | $ | 3.4 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | 15.2 | | 15.4 | | | 29.9 | | | | 16.3 | |
Gas hedging costs - recovered through fuel rates | | 0.2 | | 4.3 | | | - | | | | 1.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | 74.8 | | 82.5 | | | 134.6 | | | | 127.6 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | 23.8 | | 99.7 | |
Provision for storm damages, including hurricane costs - recovered through insurance proceeds and retail rates (Note 2 - Hurricane Isaac and Storm Cost Recovery Filings with Retail Regulators) | | | | 15.1 | | | | 8.6 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 2.9 | | 3.2 | | | 2.3 | | | | 2.6 | |
Michoud plant maintenance – recovered over a 7-year period through September 2018 | | | | 11.0 | | | | 12.9 | |
| Other | | 5.8 | | 0.6 | | | 5.5 | | | | 5.9 | |
Entergy New Orleans Total | | $125.7 | | $208.5 | | $ | 202.0 | | | $ | 178.8 | |
Entergy Texas
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $1.5 | | $1.7 | | $ | 1.2 | | | $ | 1.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | 7.2 | | 34.7 | | | 11.5 | | | | 4.5 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | | 145.9 | | 149.2 | | | 258.8 | | | | 244.9 | |
Provision for storm damages, including hurricane costs - recovered through securitization, insurance proceeds, and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | | | | | | 737.9 | | | | 822.5 | |
Transition to competition - recovered through February 2021 (Note 2 – Retail Rate Proceedings – Filings with the PUCT and Texas Cities) | | 101.9 | | 107.6 | |
Transition to competition costs - recovered over a 15-year period through February 2021 | | | | 82.1 | | | | 89.2 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 13.5 | | 12.3 | | | 9.4 | | | | 10.8 | |
| Other | | 9.9 | | 0.7 | | | 13.6 | | | | 4.9 | |
Entergy Texas Total | | $1,232.1 | | $1,117.3 | | $ | 1,114.5 | | | $ | 1,178.1 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2009 | | 2008 | | 2012 | | | 2011 | |
| | | (In Millions) | | (In Millions) | |
Asset Retirement Obligation - recovery dependent upon timing of decommissioning (Note 9) (b) | | $97.8 | | $96.1 | | $ | 58.9 | | | $ | 59.6 | |
| Unrealized loss on decommissioning trust funds | | - | | 31.3 | |
Removal costs - recovered through depreciation rates (Note 9) (b) | | 13.9 | | 14.5 | | | 56.8 | | | | 11.8 | |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b) | | | | | | | 198.2 | | | | 197.6 | |
Sale-leaseback deferral - recovered through June 2014 (Note 10 – Sale and Leaseback Transactions – Grand Gulf Lease Obligations) | | 74.6 | | 91.0 | |
Unamortized loss on reacquired debt - recovered over term of debt | | 25.0 | | 28.0 | | | 15.6 | | | | 18.2 | |
| Other | | 0.3 | | 0.4 | | | 0.6 | | | | 0.6 | |
System Energy Total | | $290.0 | | $333.4 | | $ | 330.1 | | | $ | 287.8 | |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy Gulf States Louisiana. As a result, a billing will occuroccurs monthly over the same term as the recovery and receipts will be submitted to Entergy Texas. Entergy Texas has recorded a receivable from Entergy Gulf States Louisiana and Entergy Gulf States Louisiana has recorded a corresponding payable. |
| (b) | Does not earn a return on investment, but is offset by related liabilities. |
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to portions of Entergy's service area in Louisiana, and to a lesser extent in Mississippi and Arkansas. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair or replacement of Entergy's electric facilities in areas with damage from Hurricane Isaac are currently estimated to be approximately $370 million, including approximate amounts of $7 million at Entergy Arkansas, $70 million at Entergy Gulf States Louisiana, $220 million at Entergy Louisiana, $22 million at Entergy Mississippi, and $48 million at Entergy New Orleans.
The Utility operating companies are considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. Each Utility operating company is responsible for its restoration cost obligations and for recovering or financing its storm-related costs. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. In January 2013, Entergy Gulf States Louisiana and Entergy Louisiana drew $65 million and $187 million, respectively, from their funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy recorded corresponding regulatory assets of approximately $120 million and construction work in progress of approximately $250 million. Entergy recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Correction of Regulatory Asset for Income Taxes
In the first quarter 2012, Entergy Gulf States Louisiana determined that its regulatory asset for income taxes was overstated because of a difference between the regulatory treatment of the income taxes associated with certain items (primarily pension expense) and the financial accounting treatment of those taxes. Beginning with Louisiana retail rate filings using the 1994 test year, retail rates were developed using the normalization method of accounting for income taxes. With respect to these items, however, the financial accounting for income taxes was computed using the flow-through method of accounting. As a result, over the years Entergy Gulf States Louisiana accumulated a regulatory asset representing the expected future recovery of tax expense for the affected items even though the tax expense was being collected currently in rates from customers and would not be recovered in the future.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effect was immaterial to the consolidated balance sheets, results of operations, and cash flows of Entergy for all prior reporting periods and on a cumulative basis. Therefore, a cumulative adjustment was recorded in the first quarter 2012 to remove the regulatory asset previously recorded. This adjustment increased 2012 income tax expense by $46.3 million, decreased the regulatory asset for income taxes by $75.3 million, and decreased accumulated deferred income taxes by $29 million.
The effect was also immaterial to the balance sheets, results of operations, and cash flows of Entergy Gulf States Louisiana for all prior reporting periods. Correcting the cumulative effect of the error in the first quarter 2012 could have been material to the 2012 results of operations of Entergy Gulf States Louisiana and, therefore, Entergy Gulf States Louisiana is revising its prior period financial statements to correct the errors. The corrections affect the prior period financial statements of Entergy Gulf States Louisiana as shown in the tables below:
| | | Years Ended December 31, | |
| | | 2011 | | | 2010 | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Income Statement | | | | | | | | | | | | |
| Income taxes | | $ | 88,313 | | | $ | 89,736 | | | $ | 75,878 | | | $ | 92,297 | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Earnings applicable to common equity | | $ | 202,202 | | | $ | 200,779 | | | $ | 189,911 | | | $ | 173,492 | |
| | | | | | | | | | | | | | | | | |
| Statement of Cash Flows | | | | | | | | | | | | | | | | |
| Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 190,738 | | | $ | 174,319 | |
Deferred income taxes, investment tax credits, and non-current taxes accrued | | $ | (6,268 | ) | | $ | (4,845 | ) | | $ | 87,920 | | | $ | 104,339 | |
Changes in other regulatory assets | | $ | (80,027 | ) | | $ | (77,713 | ) | | $ | 114,528 | | | $ | 141,216 | |
Other operating activities | | $ | (35,248 | ) | | $ | (37,562 | ) | | $ | 30,717 | | | $ | 4,029 | |
| | | December 31, 2011 | |
| | | As previously reported | | | As corrected | |
| | | | | | | |
| Balance Sheet | | | | | | |
| Regulatory asset for income taxes - net | | $ | 249,058 | | | $ | 173,724 | |
Accumulated deferred income taxes - current | | $ | 5,427 | | | $ | 5,107 | |
Accumulated deferred income taxes and taxes accrued | | $ | 1,397,230 | | | $ | 1,368,563 | |
| Member’s equity | | $ | 1,439,733 | | | $ | 1,393,386 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Years Ended December 31, 2011 and 2010 | |
| | | Member’s Equity | | | Total Equity | |
| | | As previously reported | | | As corrected | | | As previously reported | | | As corrected | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Statement of Changes in Equity | | | | | | |
| Balance at December 31, 2009 | | $ | 1,473,930 | | | $ | 1,445,425 | | | $ | 1,441,759 | | | $ | 1,413,254 | |
| 2010 Net income | | $ | 190,738 | | | $ | 174,319 | | | $ | 190,738 | | | $ | 174,319 | |
| Balance at December 31, 2010 | | $ | 1,539,517 | | | $ | 1,494,593 | | | $ | 1,509,213 | | | $ | 1,464,289 | |
| 2011 Net income | | $ | 203,027 | | | $ | 201,604 | | | $ | 203,027 | | | $ | 201,604 | |
| Balance at December 31, 2011 | | $ | 1,439,733 | | | $ | 1,393,386 | | | $ | 1,380,123 | | | $ | 1,333,776 | |
Fuel and purchased power cost recovery
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are allowed to recover certain fuel and purchased power costs through fuel mechanisms included in electric and gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and the current fuel and purchased power costs is generally recorded as "Deferred“Deferred fuel costs"costs” on the Utility operating companies'companies’ financial statements. The table below shows the amount of deferred fuel costs as of December 31, 20092012 and 2008,2011 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
| | 2009 | | 2008 | | 2012 | | | 2011 | |
| | (In Millions) | | (In Millions) | |
| | | | | | | | | | |
| Entergy Arkansas | $122.8 | | $119.1 | | $ | 97.3 | | | $ | 209.8 | |
| Entergy Gulf States Louisiana (a) | $57.8 | | $8.1 | | $ | 99.2 | | | $ | 2.9 | |
| Entergy Louisiana (a) | $66.4 | | ($23.6) | | $ | 94.6 | | | $ | 1.5 | |
| Entergy Mississippi | ($72.9) | | $5.0 | | $ | 26.5 | | | $ | (15.8 | ) |
| Entergy New Orleans (a) | $8.1 | | $21.8 | | $ | 1.9 | | | $ | (7.5 | ) |
| Entergy Texas | ($102.7) | | $21.2 | | $ | (93.3 | ) | | $ | (64.7 | ) |
| (a) | 20092012 and 20082011 include $100.1 million for Entergy Gulf States Louisiana, and $68 million for Entergy Louisiana, of fuel, purchased power, and capacity costs that are expected to be recovered over a period greater than twelve months. 2009 includes $4.1 million for Entergy New Orleans of fuel, purchased power, and capacity costs, thatwhich do not currently earn a return on investment and whose recovery periods are indeterminate but are expected to be recovered over a period greater than twelve months. |
Entergy Gulf States Louisiana made a $36.8 million adjustment to its deferred fuel costs in the fourth quarter 2009 relating to unrecovered nuclear fuel costs incurred since January 2008 that will now be recovered after a revision to the fuel adjustment clause methodology.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
Production Cost Allocation Rider
In its June 2007 decision on Entergy Arkansas' August 2006 rate filing, theThe APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings.proceedings, which are discussed in the “System Agreement Cost Equalization Proceedings” section below. These costs cause an increase in Entergy Arkansas'Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months. In December 2007, the APSC issued a subsequent order stating that termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
See Entergy Corporation and Subsidiaries' "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement Proceedings" for a discussion of the System Agreement proceedings.
Energy Cost Recovery Rider
Entergy Arkansas'Arkansas’s retail rates include an energy cost recovery rider. In December 2007,rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the APSC issuedtwelve-month period commencing on April 1 of each year to develop an order stating that termination of the energy cost recovery rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.
In March 2009, Entergy Arkansas filed with the APSC its annual energy cost rate, for the period April 2009 through March 2010. The filed energy cost rate decreased from $0.02456/kWh to $0.01552/kWh. The decrease was caused by the following: 1) all three of the nuclear power plants from which Entergy Arkansas obtains power, ANO 1 and 2 and Grand Gulf, had refueling outages in 2008, and the previous energy cost rate had been adjusted to account for the replacement power costs that would be incurred while these units were down; 2) Entergy Arkansas had a deferred fuel cost liability from over-recovered fuel costs at December 31, 2008, as compared to a deferred fuel cost asset from under-recovered fuel costs at December 31, 2007; offset by 3) an increase in the fuel and purchased power prices included in the calculation.
In August 2009, as provided for by its energy cost recovery rider, Entergy Arkansas filed with the APSC an interim revision to its energy cost rate. The revised energy cost rate is a decrease from $0.01552/kWh to $0.01206/kWh. The decrease was caused by a decrease in natural gas and purchased power prices from the levels used in setting the rate in March 2009. The interim revised energy cost rate went into effect for the first billing cycle of September 2009. In its order approving the new rate, the APSC ordered Entergy Arkansas to show cause why the rate should not be further reduced. In its September 14, 2009 response, Entergy Arkansas explained that it used the same methodology it had used in previous interim revisions, which is based on estimating whatredetermined annually and includes a true-up adjustment reflecting the rate would be in the next annual update based on the information known at the time. There has been no further activity in this proceeding.
APSC Investigations
In September 2005, Entergy Arkansas filed with the APSC an interim energy cost rate per the energy cost recovery rider, which provides for an interim adjustment should the cumulative over-over-recovery or under-recovery, for the energy period exceed 10 percentincluding carrying charges, of the energy costs for that period. the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In early October 2005 the APSC initiated an investigation into Entergy Arkansas'Arkansas's interim energy cost recovery rate. The investigation is focused on Entergy Arkansas'Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas'Arkansas’s March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In January 2007 the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas'Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas'Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC'sAPSC’s January 2007 order in light of the arguments advanced in Entergy Arkansas'Arkansas’s rehearing petition and because the value for Entergy Arkansas'Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. The APSC staff, the AEEC, and the Arkansas attorney general support the lifting of the stay but request additional proceedings. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas'Arkansas’s rehearing request and of the unresolved issues in the proceeding. The APSC ordered the parties to submit their unresolved issues list in the pending proceeding, which the parties have done.did. In February 2010 the APSC denied Entergy Arkansas'Arkansas’s request for rehearing, and scheduledheld a hearing forin September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concludesconcluded with testimony through September 2010. TheTestimony has been filed, and the APSC may set a hearingwill decide the case based on the record in a future order, if necessary.the proceeding, including the prefiled testimony.
Entergy Gulf States Louisiana and Entergy Louisiana
In Louisiana, Entergy Gulf States Louisiana and Entergy Louisiana recover electric fuel and purchased power costs for the upcomingbilling month based upon the level of such costs fromincurred two months prior to the priorbilling month. Entergy Gulf States Louisiana'sLouisiana’s purchased gas adjustments include estimates for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In August 2000, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Louisiana pursuant to a November 1997 LPSC general order. The time period that is the subject of the audit is January 1, 2000 through December 31, 2001. In September 2003, the LPSC staff issued its audit report and recommended a disallowance with regard to an alleged failure to uprate Waterford 3 in a timely manner. This issue was resolved with a March 2005 global settlement. Subsequent to the issuance of the audit report, the scope of this docket was expanded to include a review of annual reports on fuel and purchased power transactions with affiliates and a prudence review of transmission planning issues and to include the years 2002 through 2004. Hearings were held in November 2006. In May 2008 the ALJ issued a final recommendation that found in Entergy Louisiana's favor on the issues, except for the disallowance of hypothetical SO2 allowance costs included in affiliate purchases. The ALJ recommended a refund of the SO2 allowance costs collected to date and a realignment of these costs into base rates prospectively with an amortization of the refunded amount through base rates over a five-year period. The LPSC issued an order in December 2008 affirming the ALJ's recommendation. Entergy Louisiana recorded a provision for the disallowance, including interest, and refunded approximately $7 million to customers in 2009.
In January 2003 the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates pursuant to a November 1997 LPSC general order.affiliates. The audit will includeincluded a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause infor the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011 the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
In April 2010 the LPSC authorized its staff to initiate an audit of Entergy Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed through the fuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 1, 1995 through December 31, 2002. Discovery is underway, but a detailed2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and realign the recovery of approximately $1.0 million from Entergy Louisiana’s fuel adjustment clause to base rates. Two parties have intervened in the proceeding. A procedural schedule extending beyond the discovery stage has not yet been established, andestablished. Entergy Louisiana has recorded provisions for the LPSC staff has not yet issued its audit report. In June 2005, the LPSC expanded the audit period to include the years through 2004.estimated outcome of this proceeding.
Entergy Mississippi
Entergy Mississippi'sMississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted quarterlyannually to reflect accumulated over- or under-recoveries fromunder-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the second prior quarter.
In July 2008 the MPSC began a proceeding to investigate the fuel procurement practices and fuel adjustment schedulesauthority of the Mississippi utility companies, including Entergy Mississippi. A two-day public hearing was held in July 2008, and after a recess during which the MPSC reviewed information, the hearing resumed on August 5, 2008, for additional testimony by an expert witness retained by the MPSC. The MPSC's witness presented testimony regarding a review of the utilities' fuel adjustment clauses. The MPSC stated that the goal of the proceeding is fact-finding so that the MPSC may decide whether to amend the current fuel cost recovery process. In February 2009 the MPSC published a final report of its expert witness, which discussed Entergy Mississippi's fuel procurement activities and made recommendations regarding fuel recovery practices in Mississippi.
In addition, in October 2008 the MPSC issued an order directing Entergy Mississippi and Entergy Services to provide documents associated with fuel adjustment clause litigation in Louisiana involving Entergy Louisiana and Entergy New Orleans, and in January 2009 issued an order requiring Entergy Mississippi to provide additional information related to the long-term Evangeline gas contract that had been an issue in the fuel adjustment clause litigation in Louisiana. Entergy Mississippi and Entergy Services filed a response to the MPSC order stating that gas from the Evangeline gas contract had been sold into the Entergy System exchange and had an effect on the costs paid by Entergy Mississippi's customers. The MPSC's investigation is ongoing.
In August 2009 the MPSC retained an independent audit firm to audit Entergy Mississippi's fuel adjustment clause submittals for the period October 2007 through September 2009. The independent audit firm submitted its report to the MPSC in December 2009. The report does not recommend that any costs be disallowed for recovery. The report did suggest that some costs, less than one percent of the fuel and purchased power costs recovered during the period, may have been more reasonably charged to customers through base rates rather than through fuel charges, but the report did not suggest that customers should not have paid for those costs. In November 2009 the MPSC also retained another firm to review processes and practices related to fuel and purchased energy. The results of that review are due to the MPSC in March 2010.
In January 2010 the MPSC issued an order certifying to the Mississippi Legislature the independent audit report and the Public Utilities Staff's annual fuel audit report for the years ended September 30, 2008 and 2009, which did not find any imprudent costs. The order stated that the MPSC will open a rulemaking docket to address certain policy issues regarding allowable fuel adjustment costs, fuel adjustment mechanisms, and related matters.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigationcomplaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. OnIn December 29, 2008 the defendant Entergy companies filed to removeremoved the attorney general'sgeneral’s suit to U.S. District Court (the forumin Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy believes is appropriate to resolve the types of federal issues raised in the suit), where it is currently pending, and additionallycompanies answered the complaint and filed a counter-claimcounterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The Mississippi attorney general has filed a pleading seeking to remand the matter to state court. In May 2009 the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general'sgeneral’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Entergy New Orleans
Entergy New Orleans'Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. In June 2006 the City Council authorized the recovery of all Grand Gulf costs through Entergy New Orleans' fuel adjustment clause (a significant portion of Grand Gulf costs was previously recovered through base rates), and continued that authorization in approving the October 2006 formula rate plan filing settlement. Effective June 2009, the majority of Grand Gulf costs were realigned to base rates and are no longer flowed through the fuel adjustment clause.
Entergy New Orleans'Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005, the City Council approved modification
Entergy Corporation and Subsidiaries
Notes to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.Financial Statements
Entergy Texas
Entergy Texas'Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges,interest, not recovered in base rates. The fixed fuel factor formula was revised and approved by a PUCT order in August 2006. The new formula was implemented in September 2006. Under the new methodology, semi-annualSemi-annual revisions of the fixed fuel factor will continue to beare made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas'Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In July 2005, Entergy Texas filed with the PUCT a request for implementation of an incremental purchased capacity recovery rider. Through this rider Entergy Texas sought to recover incremental revenues that represent the incremental purchased capacity costs, including Entergy Texas' obligation to purchase power from Entergy Louisiana's Perryville plant, over what is already in Entergy Texas' base rates. The PUCT approved an initial rider to collect $18 million annually, which was increased to $21 million in subsequent years. Under the settlement of the 2007 rate case discussed below, this rider ceased on January 28, 2009, with the implementation of stipulated base rates. The amounts collected through the rider are subject to reconciliation.
In May 2006, Entergy Texas filed with the PUCT a fuel and purchased power reconciliation case covering the period September 2003 through December 2005 for costs recoverable through the fixed fuel factor rate and the incremental purchased capacity recovery rider. Entergy Texas sought reconciliation of $1.6 billion of fuel and purchased power costs on a Texas retail basis. A hearing was conducted before the ALJs in April 2007. In July 2007, the ALJs issued a proposal for decision recommending that Entergy Texas be authorized to reconcile all of its requested fixed fuel factor expenses and recommending a minor exception to the incremental purchased capacity recovery calculation. The ALJs also recommended granting an exception to the PUCT rules to allow for recovery of an additional $11.4 million in purchased power capacity costs. In September 2007, the PUCT issued an order, which affirmed the ultimate result of the ALJs' proposal for decision. Upon motions for rehearing, the PUCT added additional language in its order on rehearing to further clarify its position that 30% of River Bend should not be regulated by the PUCT. Two parties filed a second motion for rehearing, but the PUCT declined to address them. The PUCT's decision has been appealed to the Travis County District Court.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In March 2007, Entergy Texas filed a request with the PUCT to refund $78.5 million, including interest, of fuel cost recovery over-collections through January 2007. In June 2007 the PUCT approved a unanimous stipulation and settlement agreement that updated the over-collection balance through April 2007 and established a refund amount, including interest, of $109.4 million. The refund was made over a two-month period beginning with the first billing cycle in July 2007.
In October 2007, Entergy Texas filed a request with the PUCT to refund $45.6 million, including interest, of fuel cost recovery over-collections through September 2007. In January 2008, Entergy Texas filed with the PUCT a stipulation and settlement agreement among the parties that updated the over-collection balance through November 2007 and established a refund amount, including interest, of $71 million. The PUCT approved the agreement in February 2008. The refund was made over a two-month period beginning February 2008, but was reduced by $10.3 million of under-recovered incremental purchased capacity costs.
In January 2008, Entergy Texas made a compliance filing with the PUCT describing how its 2007 Rough Production Cost Equalization receipts under the System Agreement were allocated between Entergy Gulf States, Inc.'s Texas and Louisiana jurisdictions. A hearing was held at the end of July 2008, and in October 2008 the ALJ issued a proposal for decision recommending an additional $18.6 million allocation to Texas retail customers. The PUCT adopted the ALJ's proposal for decision in December 2008. Because the PUCT allocation to Texas retail customers is inconsistent with the LPSC allocation to Louisiana retail customers, the PUCT's decision would result in trapped costs between the Texas and Louisiana jurisdictions with no mechanism for recovery. The PUCT denied Entergy Texas' motion for rehearing and Entergy Texas commenced proceedings in both state and federal district courts seeking to reverse the PUCT's decision. The federal proceeding has been abated pending further action by the FERC in the proceeding discussed below. No procedural schedule has been set for the state proceeding.
Entergy Texas also filed with the FERC a proposed amendment to the System Agreement bandwidth formula to specifically calculate the payments to Entergy Gulf States Louisiana and Entergy Texas of Entergy Gulf States, Inc.'s rough production cost equalization receipts for 2007. On May 8, 2009, the FERC issued an order rejecting the proposed amendment, stating, among other things, that the FERC does not have jurisdiction over the allocation of an individual utility's receipts/payments among or between its retail jurisdictions and that this was a matter for the courts to review in the pending proceedings noted above. Because of the FERC's order, Entergy Texas recorded the effects of the PUCT's allocation of the additional $18.6 million to retail customers in the second quarter 2009. On an after-tax basis, the charge to earnings was approximately $13.0 million (including interest). Entergy requested rehearing of the FERC's order, and on July 8, 2009, the FERC granted the request for rehearing for the limited purpose of affording more time for consideration of Entergy's request.
In May 2009, Entergy Texas filed with the PUCT a request to refund $46.1 million, including interest, of fuel cost recovery over-collections through February 2009. Entergy Texas requested that the proposed refund be made over a four-month period beginning June 2009. Pursuant to a stipulation among the various parties, in June 2009 the PUCT issued an order approving a refund of $59.2 million, including interest, of fuel cost recovery overcollections through March 2009. The refund was made over a three-month period beginning July 2009, with the exception of certain industrial and seasonal/agricultural customers who received a one-month refund.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Entergy Texas requested that the proposed refund be made over a six-month period beginning January 2010. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund will bewas made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the exceptionPUCT a request to refund approximately $66 million, including interest, of certain industrial and seasonal/agriculturalfuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers who receivedover a one-month refund.three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas'Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2009 rate case filing,2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers in May 2012.
In October 2012, Entergy Texas filed with the PUCT a request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, to most customers over a three-month period beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding which is discussed below in “System Agreement Cost Equalization Proceedings”. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provided that most Entergy Texas customers would be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also includesin October 2012.
In November 2012, Entergy Texas filed a request to reconcile $1.8 billionpleading seeking a PUCT finding that special circumstances exist for limited cost recovery of fuel andcapacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased power costs covering the period April 2007 through June 2009.capacity recovery rider or other recovery mechanism.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2009 Base Rate Filing
In September 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the requirements of Arkansas law, Entergy Arkansas filed with the APSC notice of its intent to file an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2010 the MPSC issued an order: (1) providing the opportunity for a reset of Entergy Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a limit of four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.
In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Interruptible Load Proceeding
In April 2007, the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.
In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.
Storm Cost Recovery Filings with Retail RegulatorsRate Proceedings
Entergy Arkansas
Entergy Arkansas Storm Reserve Accounting
The APSC's June 2007 order in Entergy Arkansas' base rate proceeding eliminated storm reserve accounting for Entergy Arkansas. In March 2009 a law was enacted in Arkansas that requires the APSC to permit storm reserve accounting for utilities that request it. Entergy Arkansas filed its requestFilings with the APSC and has reinstated storm reserve accounting effective January 1, 2009. A hearing on Entergy Arkansas' request is scheduled for March 2010.(Entergy Arkansas)
Entergy Arkansas January Retail Rates
2009 Ice StormBase Rate Filing
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas' transmission and distribution lines, equipment, poles, and other facilities. On January 30, 2009, the APSC issued an order inviting and encouraging electric public utilities to file specific proposals for the recovery of extraordinary storm restoration expenses associated with the ice storm. On February 16,September 2009, Entergy Arkansas filed a request with the APSC for an accounting order authorizing deferrala general change in rates, charges, and tariffs. In June 2010 the APSC approved a settlement and subsequent compliance tariffs that provide for a $63.7 million rate increase, effective for bills rendered for the first billing cycle of July 2010. The settlement provides for a 10.2% return on common equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with the operating and maintenance cost portionrequirements of Entergy Arkansas' ice storm restoration costs pending their recovery. The APSC issued such an order in March 2009 subject to certain conditions, including that ifArkansas law, Entergy Arkansas seeksfiled with the APSC notice of its intent to recoverfile an application for a general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the deferred costs, those costs will be subjectdate of its notice.
Filings with the LPSC
Retail Rates - Electric
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to investigationachieve a 10.65% return on equity for whether they are incremental, prudent, and reasonable. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. On February 1, 2010, Entergy Arkansas requestedthe 2008 test year. The rate reset, a financing order to issue approximately $127.5$44.3 million in storm recovery bonds, which included carrying costs of $11.7 million and $4.6 million of up-front financing costs to pay for ice storm restoration because Entergy Arkansas' analysis demonstrates retail customers will benefit from lower costs using securitization. The APSC has established a procedural scheduleincrease that includes a hearing$36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in AprilOctober 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and statesthe LPSC staff submitted a joint report on the 2008 test year filing and requested that the APSC will issueLPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its final order by June 15, 2010. Entergy Arkansas' September 2009 general rate filing also requested recovery ofMay 19, 2010 meeting, the January 2009 ice storm costs over 10 years if it was expected that securitization would not produce lower costs for customers, and Entergy Arkansas will remove this request ifLPSC accepted the APSC approves securitization.
Entergy Texas
Hurricane Ritajoint report.
In July 2006,May 2010, Entergy Texas filed an applicationGulf States Louisiana made its formula rate plan filing with the PUCT with respect to its Hurricane Rita reconstruction costs incurred through March 2006.LPSC for the 2009 test year. The filing askedreflected a 10.25% return on common equity, which is within the PUCTallowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to determineprovide supplemental funding for the amountdecommissioning trust maintained for the LPSC-regulated 70% share of reasonable and necessary hurricane reconstruction costs eligibleRiver Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for securitization and recovery, approveincremental capacity costs. In July 2010 the recoveryLPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of carrying costs, and approve the manner in which Entergy Texas allocates those costs among its retail customer classes. In December 2006, the PUCT approved $381 million of reasonable and necessary hurricane reconstruction costs incurred through March 31, 2006, plus carrying costs, as eligible for recovery. After netting expected insurance proceeds, the amount is $353 million.service
In April 2007, the PUCT issued its financing order authorizing the issuance of securitization bonds to recover the $353 million of hurricane reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. See Note 5 to the financial statements for a discussionadjustment. The revised filing also reflected two increases outside of the June 2007 issuanceformula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the securitization bonds.LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Hurricane IkeIn May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and Hurricane Gustavtermination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Texas filedGulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an application in April 2009 seeking a determination that $577.5 million of Hurricane Ike and Hurricane Gustav restoration costs are recoverable, including estimated costs for work to be completed. On August 5, 2009, Entergy Texas submitted to the ALJ an unopposed settlement agreement intended to resolve all issues in the storm cost recovery case. Under the terms of the agreement $566.4 million, plus carrying costs, are eligible for recovery. Insurance proceeds will be credited as an offset to the securitized amount. Of the $11.1 million difference between Entergy Texas' request and the amount agreed to,11.11% earned return on common equity, which is partwithin the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the black box agreement and not directly attributable to any specific individual issues raised, $6.8formula rate plan. The filing also reflects a $22.8 million is operation and maintenance expenserate decrease for which Entergy Texas recorded a charge in the second quarter 2009. The remaining $4.3 million was recorded as utility plant. The PUCT approved the settlement in August 2009, and in September 2009 the PUCT approved recovery of the costs, plus carrying costs, by securitization. See Note 5 to the financial statements for a discussion of the November 2009 issuance of the securitization bonds.
incremental capacity costs. Entergy Gulf States Louisiana and Entergy Louisiana
Hurricane Gustavthe LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and Hurricane Ikethe LPSC approved it in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate change was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case withGulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC in May 2009. In September 2009,to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and Entergy Louisiana madethat the spin-off and merger of its transmission business with a supplemental filing to, among other things, recommend recoverysubsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the costs and replenishment of the storm reserves by Louisiana Act 55 (passed in 2007) financing.MISO/ITC Scenario, Entergy Gulf States Louisiana and Entergy Louisiana recovered their costs from Hurricane Katrina and Hurricane Rita primarily by Act 55 financing, as discussed below. On December 30, 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that, if approved, provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when Act 55 financing is accomplished. The parties to the proceeding have agreed to a procedural schedule that includes March/April 2010 hearing dates for both the recoverability and the method of recovery proceedings.requests:
Hurricane Katrina and Hurricane Rita| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
In February 2007, Entergy Louisiana and Entergy Gulf States Louisiana filed a supplemental and amending application by which they sought authority from the LPSC to securitize their Hurricane Katrina and Hurricane Rita storm cost recovery and storm reserve amounts, together with certain debt retirement costs and upfront and ongoing costs of the securitized debt issued. Securitization is authorized by a law signed by the Governor of Louisiana in May 2006. Hearings on the quantification of the amounts eligible for securitization began in late-April 2007. At the start of the hearing, a stipulation among Entergy Gulf States Louisiana, Entergy Louisiana, the LPSC staff, and most other parties in the proceeding was read into the record. The stipulation quantified the balance of storm restoration costs for recovery as $545 million for Entergy Louisiana and $187 million for Entergy Gulf States Louisiana, and set the storm reserve amounts at $152 million for Entergy Louisiana and $87 million for Entergy Gulf States Louisiana. The stipulation also called for securitization of the storm restoration costs and storm reserves in those same amounts. In August 2007, the LPSC issued orders approving recovery of the stipulated storm cost recovery and storm reserve amounts plus certain debt retirement and upfront and ongoing costs through securitization financing.| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In March 2008, Entergy Gulf States Louisiana,May 2011, Entergy Louisiana andmade its formula rate plan filing with the Louisiana Utilities Restoration Corporation (LURC),LPSC for the 2010 test year. The filing reflects an instrumentality11.07% earned return on common equity, which is just outside of the Stateallowed earnings bandwidth and results in no cost of Louisiana, filed atservice rate change under the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings).formula rate plan. The Act 55 financings are expected to produce additional customer benefits as compared to Act 64 traditional securitization. Entergy Gulf States Louisiana and Entergy Louisianafiling also filed an application requesting LPSC approvalreflects a very slight ($9 thousand) rate increase for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 3, 2008, the Louisiana State Bond Commission granted preliminary approval for the Act 55 financings. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55 financings. On April 10, 2008, Entergy Gulf States Louisiana andincremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed with the LPSCa joint report that reflects an uncontested stipulated settlement that includes Entergy Gulf States Louisiana11.07% earned return and Entergy Louisiana's proposalsresults in no cost of service rate change under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 millionformula rate plan, and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 million for five years. On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings. In May 2008, the Louisiana State Bond Commission granted final approval of the Act 55 financings.joint report in October 2011.
On July 29, 2008,In November 2011 the LPFA issued $687.7 millionLPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in bondsno cost of service rate change under the aforementioned Act 55. From the $679formula rate plan. The filing also reflected an $18.1 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserverate increase for incremental capacity costs. In August 2012, Entergy Louisiana and transferred $527submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million directlyshould be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana. From the bond proceeds received byLouisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana fromsubmitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn fromfirst-year capacity charges for the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
On August 26, 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds receivedpurchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the LURC,first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Gulf States Louisiana invested $189.4 million, including $1.7 millionon or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was withdrawn frommade on February 15, 2013. Recognizing that the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest unitsfinal structure of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation priceLouisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of $100 per unit. The preferred membership interests are callable at the option ofrates for Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.Louisiana.
Entergy Gulf States Louisiana andUnder its primary request, Entergy Louisiana do not reportassumes that it has completed integration into MISO and that the bonds on their balance sheets becausespin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the bonds are the obligation of the LPFA, and there is no recourse against Entergy, Entergy Gulf States Louisiana orMISO/ITC Scenario, Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LPFA, and remit the collections to the LPFA. By analogy to and in accordance with Entergy's accounting policy for collection of sales taxes, Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agent for the state.requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy MississippiFilings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. In March 2006, the Governor of Mississippi signed a law that established a mechanism by which the MPSC could authorize and certify an electric utility financing order and the state could issue bonds to finance the costs of repairing damage caused by Hurricane Katrina to the systems of investor-owned electric utilities. In June 2006,2010 the MPSC issued an order certifyingorder: (1) providing the opportunity for a reset of Entergy Mississippi's Hurricane Katrina restoration costs incurred through March 31, 2006Mississippi’s return on common equity to a point within the formula rate plan bandwidth and eliminating the 50/50 sharing that had been in the plan, (2) modifying the performance measurement process, and (3) replacing the revenue change limit of $89two percent of revenues, which was subject to a $14.5 million netrevenue adjustment cap, with a limit of estimated insurance proceeds. Two days later,four percent of revenues, although any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for its annual scheduled formula rate plan filing and, therefore, Entergy Mississippi will continue to use a historical test year for its annual evaluation reports under the plan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the new formula rate plan rider. In June 2010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates, but does provide for the deferral as a regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plan
In April 2009 the City Council approved a new three-year formula rate plan for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans was over- or under-earning. The formula rate plan also included a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a requestrate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The rate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the Mississippi Development Authority for $89settlement, in the third quarter 2010, Entergy Texas amortized $11 million of Community Development Block Grant (CDBG) fundingrate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for reimbursementa $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its Hurricane Katrina infrastructure restorationdecision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi also filed a Petition for Financing Order withare more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, for authorizationand the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of state bond financing of $169 million for Hurricane Katrina restoration costs and future storm costs. The $169 million amount included the $89 million of Hurricane Katrina restoration costs plus $80 million to build Entergy Mississippi's storm damage reserveAppeals for the future.D.C. Circuit. Entergy Mississippi's filing statedand the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the amount actually financed throughFERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the state bonds would be net of any CDBG funds that Entergy Mississippi received.20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.
In October 2006,2011, the Mississippi Development Authority approvedFERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for payment and Entergy Mississippi received $81 millionthe 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in CDBG funding for Hurricane Katrina costs. The MPSC then issuedthe interruptible load proceeding, which is discussed in a financing order authorizingseparate section below, the issuance of state bonds to finance $8 million of Entergy Mississippi's certified Hurricane Katrina restoration costs and $40 million for an increaseFERC concluded that the refund ruling will be held in Entergy Mississippi's storm damage reserve. $30 millionabeyance pending the outcome of the storm damage reserverehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was set asiderequired to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a restricted account. A Mississippi state entity issuedDecember 2006 compliance filing and accepted by the bondsFERC in Mayan April 2007 order. As is the case with bandwidth remedy payments, these payments and Entergy Mississippi received proceeds of $48 million. Entergy Mississippi does not report the bonds on its balance sheet because the bonds are the obligation of the state entity, and there is no recourse against Entergy Mississippi in the event of a bond default. To service the bonds, Entergy Mississippi collects a system restoration charge on behalf of the issuer, and remits the collectionsreceipts will ultimately be paid by Utility operating company customers to the issuer. By analogy to and in accordance with Entergy's accounting policy for collection of sales taxes, Entergy Mississippi does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.other Utility operating company customers.
Entergy New Orleans
In December 2005,2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Congress passedCourt of Appeals for the Katrina Relief Bill,D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a hurricane aid packagerehearing request of the May 2012 FERC order and that included CDBG funding (forrehearing request is still pending. The court also ordered that the states affected by Hurricanes Katrina, Rita,LPSC’s appeal be held in abeyance and Wilma) that allowed statethe parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and local leaders to fund individual recovery priorities. In March 2007,AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Interruptible Load Proceeding
In April 2007, the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.
In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy New Orleans incurred $205Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in storm-related costs through December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 that are eligible for CDBG funding under the state action plan,$42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and certified$4 million to Entergy New Orleans' estimated costsOrleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of $465 million for its gas system rebuild (whichthe effects is discussed below). Entergy New Orleans received $180.8 million of CDBG funds in 2007.due by August 28, 2013.
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2006 Base Rate Filing
In August 2006, Entergy Arkansas filed with the APSC a request for a change in base rates. Entergy Arkansas requested a general base rate increase (using an ROE of 11.25%), which it subsequently adjusted to a request for a $106.5 million annual increase. In June 2007, after hearings on the filing, the APSC ordered Entergy Arkansas to reduce its annual rates by $5 million, and set a return on common equity of 9.9% with a hypothetical common equity level lower than Entergy Arkansas' actual capital structure. For the purpose of setting rates, the APSC disallowed a portion of costs associated with incentive compensation based on financial measures and all costs associated with Entergy's stock-based compensation plans. In addition, under the terms of the APSC's decision, the order eliminated storm reserve accounting and set an amount of $14.4 million in base rates to address
Entergy Corporation and Subsidiaries
Notes to Financial Statements
storm restoration costs, regardless of the actual annual amount of future restoration costs. The APSC's June 2007 decision left Entergy Arkansas with no mechanism to recover $52 million of costs previously accumulated in Entergy Arkansas' storm reserve and $18 million of removal costs associated with the termination of a lease.
The APSC denied Entergy Arkansas' request for rehearing of its June 2007 decision, and the base rate change was implemented August 29, 2007, effective for bills rendered after June 15, 2007. In December 2008 the Arkansas Court of Appeals upheld almost all aspects of the APSC decision. After considering the progress of the proceeding in light of the decision of the Court of Appeals, Entergy Arkansas recorded in the fourth quarter 2008 an approximately $70 million charge to earnings, on both a pre- and after-tax basis because these are primarily flow-through items, to recognize that the regulatory assets associated with the storm reserve costs, lease termination removal costs, and stock-based compensation are no longer probable of recovery. In April 2009 the Arkansas Supreme Court denied Entergy Arkansas' petition for review of the Court of Appeals decision.
2009 Base Rate Filing
OnIn September 4, 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. Entergy Arkansas requestedIn June 2010 the APSC approved a $223.2settlement and subsequent compliance tariffs that provide for a $63.7 million base rate increase, that would become effective infor bills rendered for the first billing cycle of July 2010. The filing reflects an 11.5%settlement provides for a 10.2% return on common equity using a projected capital structure, and proposes a formula rate plan mechanism. Proposed formula rate plan provisions include a +/- 25 basis point bandwidth, with earnings outside the bandwidth reset to the 11.5% return on common equity midpoint and rates changing on a prospective basis depending on whether Entergy Arkansas is over or under-earning. The proposed formula rate plan also includes a recovery mechanism for APSC-approved costs for additional capacity purchases or construction/acquisition of new transmission or generating facilities. Entergy Arkansas is also seeking an increase in its annual storm damage accrual from $14.4 million to $22.3 million. The APSC scheduled hearings in the proceeding beginning in May 2010.equity.
Filings2013 Base Rate Filing
On December 31, 2012, in accordance with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009,requirements of Arkansas law, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The filing includes a proposed cost of service adjustment rider with a three-year term beginning with the 2010 calendar year as the initial evaluation period. Key provisions include a plus or minus 15 basis point bandwidth, with earnings outside the bandwidth reset to the bottom or top of the band and rates changing prospectively depending upon whether Entergy Texas is under or over-earning. The annual change in revenue requirement is limited to a percentage change in the Consumer Price Index for urban areas, and the filing includes a provision for extraordinary events greater than $10 million per year that would be considered separately. The filing also proposes a purchased power recovery rider and a competitive generation service tariff and will establish test year baseline values to be used in the transmission cost recovery factor rider authorized for use by Entergy Texas in the 2009 legislative session. The rate case also includes a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Hearings in the proceeding are scheduled for July 2010, and the PUCT is required to issue a final order by November 1, 2010. Beginning in May 2010, Entergy Texas will be allowed to implement a $17.5 million interim rate increase, subject to refund. The rates set by a final order will be effective back to September 13, 2010.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2007 Rate Case
Entergy Texas made a rate filing in September 2007 with the PUCT requesting an annual rate increase totaling $107.5 million, including a base rate increase of $64.3 million and riders totaling $43.2 million. On December 16, 2008, Entergy Texas filed a term sheet that reflected a settlement agreement that included the PUCT Staff and the other active participants in the rate case. On December 19, 2008, the ALJs approved Entergy Texas' request to implement interim rates reflecting the agreement. The agreement includes a $46.7 million base rate increase, among other provisions. Under the ALJs' interim order, Entergy Texas implemented interim rates, subject to refund and surcharge, reflecting the rates established through the settlement. These rates became effective with bills rendered on and after January 28, 2009, for usage on and after December 19, 2008. In addition, the existing recovery mechanism for incremental purchased power capacity costs ceased as of January 28, 2009, with purchased power capacity costs then subsumed within the base rates set in this proceeding. The agreement adopted by the PUCT also reconciles fuel and purchased power costs for the period January 1, 2006 through March 31, 2007. Certain Texas municipalities exercised their original jurisdiction and took final action to approve rates consistent with the interim rates approved by the ALJs. In March 2009, the PUCT approved the settlement, which made the interim rates final.
Transition to Competition Costs
In August 2005, Entergy TexasArkansas filed with the PUCTAPSC notice of its intent to file an application for recoverya general change or modification in its rates and tariffs no sooner than 60 days and no longer than 90 days from the date of its transition to competition costs. Entergy Texas requested recovery of $189 million in transition to competition costs through implementation of a 15-year rider. The $189 million represents transition to competition costs Entergy Texas incurred from June 1, 1999 through June 17, 2005 in preparing for the potential of competition in its Texas service area, including attendant AFUDC, and all carrying costs projected to be incurred on the transition to competition costs through February 28, 2006. The $189 million is before any gross-up for taxes or carrying costs over the 15-year recovery period. Entergy Texas reached a unanimous settlement agreement, which the PUCT approved in June 2006, on all issues with the active parties in the transition to competition cost recovery case. The agreement allows Entergy Texas to recover $14.5 million per year in transition to competition costs over a 15-year period. Entergy Texas implemented rates based on this revenue level on March 1, 2006.notice.
Filings with the LPSC
Formula Rate Plans (Entergy Gulf States Louisiana and Entergy Louisiana)
In March 2005, the LPSC approved a settlement proposal to resolve various dockets covering a range of issues for Entergy Gulf States Louisiana and Entergy Louisiana. The settlement included the establishment of a three-year formula rate plan for Entergy Gulf States Louisiana that, among other provisions, establishes a return on common equity mid-point of 10.65% for the initial three-year term of the plan and permits Entergy Gulf States Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed range of 9.9% to 11.4% are allocated 60% to customers and 40% to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana made its initial formula rate plan filing in June 2005. The formula rate plan was subsequently extended one year.
Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase in January 2004. In May 2005 the LPSC approved a settlement that included the adoption of a three-year formula rate plan, the terms of which included an ROE mid-point of 10.25% for the initial three-year term of the plan and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing was made in May 2006.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As discussed below the formula rate plans for Entergy Gulf States Louisiana and Entergy Louisiana have been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, and 2010 test years.
Retail Rates - Electric
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolves Entergy Louisiana's 2006 and 2007 test year filings. The settlement provides for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. 10.25% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%). The rate reset, a $2.5 million increase that includes a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset will be subject to refund pending review of the 2008 test year filing that was made on October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlement Entergy Louisiana refunded to its customers $12.9 million, which includes interest, in the November 2009 billing cycle. The LPSC Staff and one intervenor filed comments on the 2008 test year filing in January 2010. Entergy Louisiana has until March 2010 to provide an initial response to the proposed adjustments and discovery is ongoing. Entergy Louisiana will implement any agreed changes by March 15, 2010. A procedural schedule to address any contested issues would be set after March 15, 2010.
In December 2009, Entergy Louisiana filed an application seeking LPSC approval for a $10.3 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Currently, Entergy Louisiana has $2.2 million in annual retail rates for decommissioning funding.
In May 2008, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2007 test year, seeking an $18.4 million rate increase, comprised of $12.6 million of recovery of incremental and deferred capacity costs and $5.8 million based on a cost of service revenue deficiency related to continued lost contribution to fixed costs associated with the loss of customers due to Hurricane Katrina. In August 2008, Entergy Louisiana implemented a $43.9 million formula rate plan decrease to remove interim storm cost recovery and to reduce the storm damage accrual. Entergy Louisiana then implemented a $16.9 million formula rate plan increase, subject to refund, effective the first billing cycle in September 2008, comprised of $12.6 million of recovery of incremental and deferred capacity costs and $4.3 million based on a cost of service deficiency.
In May 2007, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2006 test year, indicating a 7.6% earned return on common equity. In September 2007, Entergy Louisiana modified its formula rate plan filing to reflect its implementation of certain adjustments proposed by the LPSC Staff in its review of Entergy Louisiana's original filing with which Entergy Louisiana agreed, and to reflect its implementation of an $18.4 million annual formula rate plan increase comprised of (1) a $23.8 million increase representing 60% of Entergy Louisiana's revenue deficiency, and (2) a $5.4 million decrease for reduced incremental and deferred capacity costs. In October 2007, Entergy Louisiana implemented a $7.1 million formula rate plan decrease that was due primarily to the reclassification of certain franchise fees from base rates to collection via a line item on customer bills pursuant to an LPSC Order.
In May 2006, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2005 test year. Entergy Louisiana modified the filing in August 2006 to reflect a 9.45% return on equity which is within the allowed bandwidth. The modified filing includes an increase of $24.2 million for interim recovery of storm costs from Hurricanes Katrina and Rita and a $119.2 million rate increase to recover LPSC-approved incremental deferred and ongoing capacity costs. The filing requested recovery of approximately $50 million for the amortization of capacity deferrals over a three-year period, including carrying charges, and approximately $70 million for ongoing capacity costs. The increase was implemented, subject to refund, with the first billing cycle of September 2006. Entergy Louisiana subsequently updated its formula rate plan rider to reflect adjustments proposed by the LPSC Staff with which it agrees. The adjusted return on equity of 9.56% remains within the allowed bandwidth. Ongoing and deferred incremental capacity costs were reduced to $118.7 million. The
Entergy Corporation and Subsidiaries
Notes to Financial Statements
updated formula rate plan rider was implemented, subject to refund, with the first billing cycle of October 2006. An uncontested stipulated settlement was filed in February 2008 that left the current base rates in place, and the LPSC approved the settlement in March 2008. In the settlement Entergy Louisiana agreed to credit customers $7.2 million, plus $0.7 million of interest, for customer contributions to the Central States Compact in Nebraska that was never completed and agreed to a one-time $2.6 million deduction from the deferred capacity cost balance. The credit, for which Entergy Louisiana had previously recorded a provision, was made in May 2008.
(Entergy Gulf States Louisiana)
In October 2009 the LPSC approved a settlement that resolvesresolved Entergy Gulf States Louisiana'sLouisiana’s 2007 test year filing. The settlement providesfiling and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Gulf States Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.65% return on equity for the 2008 test year. 10.65% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset will bewas subject to refund pending review of the 2008 test year filing that was made onin October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Gulf States Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlement Entergy Gulf States Louisiana refunded to its customers $3.7 million, which includes interest, in the November 2009 billing cycle. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. The discoveryIn May 2010, Entergy Gulf States Louisiana and comment period forthe LPSC staff submitted a joint report on the 2008 test year filing is currently open, and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana will implement any agreed changes by March 15, 2010. A procedural schedule to address any contested issues would be set after March 15, 2010.
In Decembermade its formula rate plan filing with the LPSC for the 2009 Entergy Gulf States Louisiana filed an application seeking LPSC approval fortest year. The filing reflected a $9.7 million10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to ana NRC notification of a projected shortfall of decommissioning funding assurance. Currently,The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana's annual retailLouisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates contain no amount for decommissioning funding.reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2008,2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 20072010 test year. The filing reflected a 9.26%reflects an 11.11% earned return on common equity, which was belowis within the allowed earnings bandwidth, and indicatedindicating no cost of service rate change is necessary under the formula rate plan. The filing also reflects a $5.4$22.8 million revenue deficiency, offset by a $4.1 millionrate decrease in required additionalfor incremental capacity costs. Entergy Gulf States Louisiana implementedand the LPSC Staff subsequently filed a $20.7 millionjoint report that also stated that no cost of service rate change is necessary under the formula rate plan, decrease, subject to refund, effectiveand the first billing cycleLPSC approved it in September 2008. The decrease included removalOctober 2011.
In November 2011 the LPSC approved a one-year extension of interim storm cost recovery and a reduction in the storm damage accrual. Entergy Gulf States Louisiana then implemented a $16.0 millionLouisiana’s formula rate plan increase, subject to refund, effective the first billing cycle in October 2008 to collect previously deferred and ongoing costs associated with LPSC approved additional capacity, including the Ouachita power plant. In November 2008 Entergy Gulf States Louisiana filed to implement an additional increase of $9.3 million to recover the costs of a new purchased power agreement.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
plan. In May 2007,2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 20062011 test year. The filing reflected a 10.0%an 11.94% earned return on common equity, which was withinis above the allowed earnings bandwidth and an anticipatedwould indicate a $6.5 million cost of service rate change was necessary under the formula rate planplan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of $2311.86% indicating a $5.7 million annually attributablecost of service rate decrease is necessary under the formula rate plan. The revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to adjustments outsiderefund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan sharing mechanism related to capacity costs and the anticipated securitization of storm costs related to Hurricane Katrina and Hurricane Rita and2011 test year, the securitization ofLPSC required that a storm reserve. In September 2007,base rate case be filed by Entergy Gulf States Louisiana, modifiedand the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
(Entergy Louisiana)
In October 2009 the LPSC approved a settlement that resolved Entergy Louisiana’s 2006 and 2007 test year filings and provided for a new formula rate plan for the 2008, 2009, and 2010 test years. 10.25% is the target midpoint return on equity for the formula rate plan, filingwith an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%).
Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reflectreset its rates to achieve a 10.07%10.25% return on common equity whichfor the 2008 test year. The rate reset, a $2.5 million increase that included a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was still withinimplemented for the allowed bandwidth. The modified filing also reflected implementation of a $4.1 millionNovember 2009 billing cycle, and the rate increase,reset was subject to refund attributable topending review of the 2008 test year filing that was made in October 2009. In April 2010, Entergy Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana moved the recovery of additional LPSC-approved incremental deferred and ongoing capacity costs. The rate decrease anticipated in the original filing did not occur becauseapproximately $12.5 million of the additional capacity costs approved byfrom fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 meeting, the LPSC and because securitization of storm costs associated with Hurricane Katrina and Hurricane Rita andaccepted the establishment of a storm reserve had not yet occurred. In October 2007, Entergy Gulf States Louisiana implemented a $16.4 million formula rate plan decrease that was due to the reclassification of certain franchise fees from base rates to collection via a line item on customer bills pursuant to an LPSC order. In March 2008 the LPSC approved an uncontested stipulated settlement that left the current base rates in place and extended the formula rate plan for one year.joint report.
In May 2006,2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 20052009 test year. Entergy Gulf States Louisiana modified theThe filing in August 2006 to reflect an 11.1%reflected a 10.82% return on common equity, which is within the allowed bandwidth.earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The modified filing includesdoes reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Louisiana made a revised 2009 test year formula rate plan increasefiling. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of $17.2service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously-approved decommissioning revenue requirement, and (2) $2.2 million annually that provides for 1) interim recovery of $10.5 million of storm costs from Hurricane Katrina and Hurricane Rita and 2) recovery of $6.7 million of LPSC-approved incremental deferred and ongoing capacity costs. The increase was implementedrates reflected in the revised filing became effective beginning with the first billing cycle of September 2006. In May 2007 the LPSC approved a settlement between2010. Entergy Gulf States Louisiana and the LPSC staff affirmingsubsequently submitted a joint report on the rates2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflects an 11.07% earned return on common equity, which is just outside of the allowed earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana and the LPSC Staff subsequently filed a joint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, and the LPSC approved the joint report in October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan. In May 2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected a 9.63% earned return on common equity, which is within the earnings bandwidth and results in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $15.9 million should be reflected in the incremental capacity rider. The rate change was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review. With completion of the Waterford 3 replacement steam generator project, the LPSC will undertake a prudence review in September 2006.connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Louisiana.
Under its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Under the alternative request contained in its filing, Entergy Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates - Gas (Entergy Gulf States Louisiana)
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18%, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points. The sixty day review and comment period for this filing remains open.
In January 2009, Entergy Gulf States Louisiana filed with the LPSC its gaspoints, resulting in no rate stabilization plan for the test year ended September 30, 2008. The filing showed a revenue deficiency of $529 thousand based on a return on common equity mid-point of 10.5%.change. In April 2009, Entergy Gulf States Louisiana implemented a $255 thousand rate increase pursuant to an uncontested settlement with the LPSC staff.
In January 2008, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ending September 30, 2007. The filing showed a revenue deficiency of $3.7 million based on a return on common equity mid-point of 10.5%. Entergy Gulf States Louisiana implemented a $3.4 million rate increase in April 2008 pursuant to an uncontested agreement with the LPSC staff.
In January 2007, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ending September 30, 2006. The filing showed a revenue deficiency of $3.5 million based on a return on common equity mid-point of 10.5%. In March 2007,2010, Entergy Gulf States Louisiana filed a set of rate and rider schedules that reflected all proposed LPSC staff adjustments and implemented a $2.4 million base rate increase effectiverevised evaluation report reflecting changes agreed upon with the first billing cycle of April 2007 pursuant to theLPSC Staff. The revised evaluation report also resulted in no rate stabilization plan.change.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. The proposed modifications include:In March 2010 the MPSC issued an order: (1) resettingproviding the opportunity for a reset of Entergy Mississippi'sMississippi’s return on common equity to the middle ofa point within the formula rate plan bandwidth each year and eliminating the 50/50 sharing that had been in the current plan, (2) modifying the performance measurement process, and (3) replacing the current raterevenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a proposed limit of four percent of revenues, (3) implementingalthough any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi’s request to use a projected test year for the annual filing and subsequent look-back for the prior year, and (4) modifying the performance measurement process.
In March 2009, Entergy Mississippi made with the MPSC its annual scheduled formula rate plan filing for the 2008 test year. The filing reported a $27.0 million revenue deficiency and, an earned return on common equity of 7.41%.therefore, Entergy Mississippi requestedwill continue to use a $14.5 million increase inhistorical test year for its annual electric revenues, which is the maximum increase allowedevaluation reports under the terms ofplan.
In March 2010, Entergy Mississippi submitted its 2009 test year filing, its first annual filing under the formula rate plan. The MPSC issued an order on June 30, 2009, finding that Entergy Mississippi's earned return was sufficiently below the lower bandwidth limit set by thenew formula rate plan to require a $14.5 million increase in annual revenues, effective for bills rendered on or after June 30, 2009.
In March 2008, Entergy Mississippi made its annual scheduled formula rate plan filing for the 2007 test year with the MPSC. The filing showed that a $10.1 million increase in annual electric revenues is warranted.rider. In June 2008, Entergy Mississippi reached a settlement with the Mississippi Public Utilities Staff that would result in a $3.8 million rate increase. In January 2009 the MPSC rejected the settlement and left the current rates in effect. Entergy Mississippi appealed the MPSC's decision to the Mississippi Supreme Court. After the decision of the MPSC regarding the formula rate plan filing for the 2008 test year, Entergy Mississippi filed a motion to dismiss its appeal to the Mississippi Supreme Court.
In March 2007, Entergy Mississippi made its annual scheduled formula rate plan filing for the 2006 test year with the MPSC. The filing showed that an increase of $12.9 million in annual electric revenues is warranted. In June 20072010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities staffStaff that provides for no change in rates, but does provide for the deferral as a $10.5regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate increase,plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which was effective beginning with July 2007 billings.is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
Filings with the City Council (Entergy New Orleans)
Formula Rate Plans and Storm-related RidersPlan
On July 31, 2008, Entergy New Orleans filed an electric and gas base rate case with the City Council. OnIn April 2, 2009 the City Council approved a comprehensive settlement. The settlement provided for a net $35.3 million reduction in combined fuel and non-fuel electric revenue requirement, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and substantial realignment of Grand Gulf cost recovery from fuel to electric base rates, and a $4.95 million gas base rate increase, both effective June 1, 2009, with adjustment of the customer charges for all rate classes. A new three-year formula rate plan was also adopted,for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans iswas over- or under-earning. The formula rate plan also includesincluded a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council’s Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October 2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement also included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The programsrate case also included a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are expectedpartially responsible, in response to beginan NRC notification of a projected shortfall of decommissioning funding assurance. Beginning in May 2010, Entergy Texas implemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The parties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas’s fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
2011 Rate Case
In November 2011, Entergy Texas filed a rate case requesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT voted not to address the purchased power recovery rider in the current rate case, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate
Entergy Corporation and Subsidiaries
Notes to Financial Statements
proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $66 million and a 9.6% return on common equity. The PUCT Staff, however, subsequently filed a statement of position in the proceeding indicating that it was still evaluating the position it would ultimately take in the case regarding Entergy Texas’s recovery of purchased power capacity costs and Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012 the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of 9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, stating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in the calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, have appealed the PUCT’s order to the Travis County District Court.
System Agreement Cost Equalization Proceedings
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC. The proceedings include challenges to the allocation of costs as defined by the System Agreement and allegations of imprudence by the Utility operating companies in their execution of their obligations under the System Agreement.
In June 2005, the FERC issued a decision in System Agreement litigation that had been commenced by the LPSC, and essentially affirmed its decision in a December 2005 order on rehearing. The FERC decision concluded, among other things, that:
| · | The System Agreement no longer roughly equalizes total production costs among the Utility operating companies. |
| · | In order to reach rough production cost equalization, the FERC imposed a bandwidth remedy by which each company’s total annual production costs will have to be within +/- 11% of Entergy System average total annual production costs. |
| · | In calculating the production costs for this purpose under the FERC’s order, output from the Vidalia hydroelectric power plant will not reflect the actual Vidalia price for the year but is priced at that year’s average price paid by Entergy Louisiana for the exchange of electric energy under Service Schedule MSS-3 of the System Agreement, thereby reducing the amount of Vidalia costs reflected in the comparison of the Utility operating companies’ total production costs. |
| · | The remedy ordered by FERC in 2005 required no refunds and became effective based on calendar year 2006 production costs and the first reallocation payments were made in 2007. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The FERC’s decision reallocates total production costs of the Utility operating companies whose relative total production costs expressed as a percentage of Entergy System average production costs are outside an upper or lower bandwidth. Under the current circumstances, this will be accomplished by payments from Utility operating companies whose production costs are more than 11% below Entergy System average production costs to Utility operating companies whose production costs are more than the Entergy System average production cost, with payments going first to those Utility operating companies whose total production costs are farthest above the Entergy System average.
Assessing the potential effects of the FERC’s decision requires assumptions regarding the future total production cost of each Utility operating company, which assumptions include the mix of solid fuel and gas-fired generation available to each company and the costs of natural gas and purchased power. Entergy Louisiana, Entergy Gulf States Louisiana, Entergy Texas, and Entergy Mississippi are more dependent upon gas-fired generation sources than Entergy Arkansas or Entergy New Orleans. Of these, Entergy Arkansas is the least dependent upon gas-fired generation sources. Therefore, increases in natural gas prices likely will increase the amount by which Entergy Arkansas’s total production costs are below the Entergy System average production costs.
The LPSC, APSC, MPSC, and the Arkansas Electric Energy Consumers appealed the FERC’s December 2005 decision to the United States Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit concluded that the FERC’s orders had failed to adequately explain both its conclusion that it was prohibited from ordering refunds for the 20-month period from September 13, 2001 - May 2, 2003 and its determination to implement the bandwidth remedy commencing on January 1, 2006, rather than June 1, 2005. The D.C. Circuit remanded the case to the FERC for further proceedings on these issues.
In October 2011, the FERC issued an order addressing the D.C. Circuit remand on these two issues. On the first issue, the FERC concluded that it did have the authority to order refunds, but decided that it would exercise its equitable discretion and not require refunds for the 20-month period from September 13, 2001 - May 2, 2003. Because the ruling on refunds relied on findings in the interruptible load proceeding, which is discussed in a separate section below, the FERC concluded that the refund ruling will be held in abeyance pending the outcome of the rehearing requests in that proceeding. On the second issue, the FERC reversed its prior decision and ordered that the prospective bandwidth remedy begin on June 1, 2005 (the date of its initial order in the proceeding) rather than January 1, 2006, as it had previously ordered. Pursuant to the October 2011 order, Entergy was required to calculate the additional bandwidth payments for the period June - December 2005 utilizing the bandwidth formula tariff prescribed by the FERC that was filed in a December 2006 compliance filing and accepted by the FERC in an April 2007 order. As is the case with bandwidth remedy payments, these payments and receipts will ultimately be paid by Utility operating company customers to other Utility operating company customers.
In December 2011, Entergy filed with the FERC its compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s October 2011 order. The filing shows the following payments/receipts among the Utility operating companies:
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | 156 | |
| Entergy Gulf States Louisiana | | $ | (75 | ) |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | (33 | ) |
| Entergy New Orleans | | $ | (5 | ) |
| Entergy Texas | | $ | (43 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas made its payment in January 2012. In February 2012, Entergy Arkansas filed for an interim adjustment to its production cost allocation rider requesting that the $156 million payment be collected from customers over the 22-month period from March 2012 through December 2013. In March 2012 the APSC issued an order stating that the payment can be recovered from retail customers through the production cost allocation rider, subject to refund. The LPSC and the APSC have requested rehearing of the FERC’s October 2011 order. The APSC, the LPSC, the PUCT, and other parties intervened in the December 2011 compliance filing proceeding, and the APSC and the LPSC also filed protests.
Calendar Year 2012 Production Costs
The liabilities and assets for the preliminary estimate of the payments and receipts required to implement the FERC’s remedy based on calendar year 2012 production costs were recorded in December 2012, based on certain year-to-date information. The preliminary estimate was recorded based on the following estimate of the payments/receipts among the Utility operating companies for 2013.
| | | Payments or (Receipts) | |
| | | (In Millions) | |
| Entergy Arkansas | | $ | - | |
| Entergy Gulf States Louisiana | | $ | - | |
| Entergy Louisiana | | $ | - | |
| Entergy Mississippi | | $ | - | |
| Entergy New Orleans | | $ | (17 | ) |
| Entergy Texas | | $ | 17 | |
The actual payments/receipts for 2013, based on calendar year 2012 production costs, will not be calculated until the Utility operating companies’ 2012 FERC Form 1s have been filed. Once the calculation is completed, it will be filed at the FERC. The level of any payments and receipts is significantly affected by a number of factors, including, among others, weather, the price of alternative fuels, the operating characteristics of the Entergy System generating fleet, and multiple factors affecting the calculation of the non-fuel related revenue requirement components of the total production costs, such as plant investment.
Rough Production Cost Equalization Rates
Each May since 2007 Entergy has filed with the FERC the rates to implement the FERC’s orders in the System Agreement proceeding. These filings show the following payments/receipts among the Utility operating companies are necessary to achieve rough production cost equalization as defined by the FERC’s orders:
| | | 2007 Pmts (Rcts) | | | 2008 Pmts (Rcts) | | | 2009 Pmts (Rcts) | | | 2010 Pmts (Rcts) | | | 2011 Pmts (Rcts) | | | 2012 Pmts (Rcts) | |
| | | (In Millions) | |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | $ | 252 | | | $ | 252 | | | $ | 390 | | | $ | 41 | | | $ | 77 | | | $ | 41 | |
| Entergy Gulf States La. | | $ | (120 | ) | | $ | (124 | ) | | $ | (107 | ) | | $ | - | | | $ | (12 | ) | | $ | - | |
| Entergy Louisiana | | $ | (91 | ) | | $ | (36 | ) | | $ | (140 | ) | | $ | (22 | ) | | $ | - | | | $ | (41 | ) |
| Entergy Mississippi | | $ | (41 | ) | | $ | (20 | ) | | $ | (24 | ) | | $ | (19 | ) | | $ | (40 | ) | | $ | - | |
| Entergy New Orleans | | $ | - | | | $ | (7 | ) | | $ | - | | | $ | - | | | $ | (25 | ) | | $ | - | |
| Entergy Texas | | $ | (30 | ) | | $ | (65 | ) | | $ | (119 | ) | | $ | - | | | $ | - | | | $ | - | |
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Management believes that any changes in the allocation of production costs resulting from the FERC’s decision and related retail proceedings should result in similar rate changes for retail customers, subject to specific circumstances that have caused trapped costs. See “Fuel and purchased power cost recovery, Entergy Texas,” above for discussion of a
Entergy Corporation and Subsidiaries
Notes to Financial Statements
PUCT decision that resulted in $18.6 million of trapped costs between Entergy’s Texas and Louisiana jurisdictions. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” below for a discussion of a FERC decision that could result in trapped costs at Entergy Arkansas related to its contract with AmerenUE.
Entergy Arkansas, and, for December 2012, Entergy Texas, records accounts payable and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, made its annual formula rate plan filings with the City Council. The filings presented various alternativesand Entergy Texas record accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. Entergy Arkansas, and, for December 2012, Entergy Texas, records a corresponding regulatory asset for its right to collect the payments from its customers, and Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas record corresponding regulatory liabilities for their obligations to pass the receipts on to their customers. The regulatory asset and liabilities are shown as “System Agreement cost equalization” on the respective balance sheets.
2007 Rate Filing Based on Calendar Year 2006 Production Costs
Several parties intervened in the 2007 rate proceeding at the FERC, including the APSC, the MPSC, the Council, and the LPSC, which have also filed protests. The PUCT also intervened. Intervenor testimony was filed in which the intervenors and also the FERC Staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for nuclear facilities. The effect of the various positions would be to reallocate costs among the Utility operating companies. The Utility operating companies filed rebuttal testimony explaining why the bandwidth payments are properly recoverable under the AmerenUE contract, and explaining why the positions of FERC Staff and intervenors on the other issues should be rejected. A hearing in this proceeding concluded in July 2008, and the ALJ issued an initial decision in September 2008. The ALJ’s initial decision concluded, among other things, that: (1) the decisions to not exercise Entergy Arkansas’s option to purchase the Independence plant in 1996 and 1997 were prudent; (2) Entergy Arkansas properly flowed a portion of the bandwidth payments through to AmerenUE in accordance with the wholesale power contract; and (3) the level of nuclear depreciation and decommissioning expense reflected in the bandwidth calculation should be calculated based on NRC-authorized license life, rather than the nuclear depreciation and decommissioning expense authorized by the retail regulators for purposes of retail ratemaking. Following briefing by the parties, the matter was submitted to the FERC for decision. On January 11, 2010, the FERC issued its decision both affirming and overturning certain of the ALJ’s rulings, including overturning the decision on nuclear depreciation and decommissioning expense. The FERC’s conclusion related to the AmerenUE contract does not permit Entergy Arkansas to recover a portion of its bandwidth payment from AmerenUE. The Utility operating companies requested rehearing of that portion of the decision and requested clarification on certain other portions of the decision.
AmerenUE argued that its wholesale power contract with Entergy Arkansas, pursuant to which Entergy Arkansas sells power to AmerenUE, does not permit Entergy Arkansas to flow through to AmerenUE any portion of Entergy Arkansas’s bandwidth payment. The AmerenUE contract expired in August 2009. In April 2008, AmerenUE filed a complaint with the FERC seeking refunds, plus interest, in the event the FERC ultimately determines that bandwidth payments are not properly recovered under the AmerenUE contract. In response to the FERC’s decision discussed in the previous paragraph, Entergy Arkansas recorded a regulatory provision in the fourth quarter 2009 for a potential refund to AmerenUE.
In May 2012, the FERC issued an order on rehearing in the proceeding. The order may result in the reallocation of costs among the Utility operating companies, although there are still FERC decisions pending in other System Agreement proceedings that could affect the rough production cost equalization payments and receipts. The FERC directed Entergy, within 45 days of the issuance of a pending FERC order on rehearing regarding the functionalization of costs in the 2007 rate filing, to file a comprehensive bandwidth recalculation report showing updated payments and receipts in the 2007 rate filing proceeding. The May 2012 FERC order also denied Entergy’s request for rehearing regarding the AmerenUE contract and ordered Entergy Arkansas to refund to
Entergy Corporation and Subsidiaries
Notes to Financial Statements
AmerenUE the rough production cost equalization payments collected from AmerenUE. Under the terms of the FERC’s order a refund of $30.6 million, including interest, was made in June 2012. Entergy and the LPSC appealed certain aspects of the FERC’s decisions to the U.S. Court of Appeals for the D.C. Circuit. On December 7, 2012, the D.C. Circuit dismissed Entergy’s petition for review as premature because Entergy filed a rehearing request of the May 2012 FERC order and that rehearing request is still pending. The court also ordered that the LPSC’s appeal be held in abeyance and that the parties file motions to govern further proceedings within 30 days of the FERC’s completion of the ongoing "Entergy bandwidth proceedings."
2008 Rate Filing Based on Calendar Year 2007 Production Costs
Several parties intervened in the 2008 rate proceeding at the FERC, including the APSC, the LPSC, and AmerenUE, which have also filed protests. Several other parties, including the MPSC and the City Council, have intervened in the proceeding without filing a protest. In direct testimony filed on January 9, 2009, certain intervenors and also the FERC staff advocated a number of positions on issues that affect the level of production costs the individual Utility operating companies are permitted to reflect in the bandwidth calculation, including the level of depreciation and decommissioning expense for the nuclear and fossil-fueled generating facilities. The effect of these various positions would be to reallocate costs among the Utility operating companies. In addition, three issues were raised alleging imprudence by the Utility operating companies, including whether the Utility operating companies had properly reflected generating units’ minimum operating levels for purposes of making unit commitment and dispatch decisions, whether Entergy Arkansas’s sales to third parties from its retained share of the Grand Gulf nuclear facility were reasonable, prudent, and non-discriminatory, and whether Entergy Louisiana’s long-term Evangeline gas purchase contract was prudent and reasonable.
The parties reached a partial settlement agreement of certain of the issues initially raised in this proceeding. The partial settlement agreement was conditioned on the FERC accepting the agreement without modification or condition, which the FERC did on August 24, 2009. A hearing on the remaining issues in the proceeding was completed in June 2009, and in September 2009 the ALJ issued an initial decision. The initial decision affirms Entergy’s position in the filing, except for two issues that may result in a reallocation of costs among the Utility operating companies. In October 2011 the FERC issued an order on the ALJ’s initial decision. The FERC’s order resulted in a minor reallocation of payments/receipts among the Utility operating companies on one issue in the 2008 rate filing. Entergy made a compliance filing in December 2011 showing the updated payment/receipt amounts. The LPSC filed a protest in response to the compliance filing. On January 3, 2013, the FERC issued an order accepting Entergy’s compliance filing. In the January 2013 order the FERC required Entergy to include interest on the recalculated bandwidth payment and receipt amounts for the period from June 1, 2008 until the date of the Entergy intra-system bill that will reflect the bandwidth recalculation amounts for calendar year 2007. On February 4, 2013, Entergy filed a request for rehearing of the FERC’s ruling requiring interest.
2009 Rate Filing Based on Calendar Year 2008 Production Costs
Several parties intervened in the 2009 rate proceeding at the FERC, including the LPSC and Ameren, which have also filed protests. In July 2009 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2009, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures were terminated and a hearing before the ALJ was held in April 2010. In August 2010 the ALJ issued an initial decision. The initial decision substantially affirms Entergy's position in the filing, except for one issue that may result in some reallocation of costs among the Utility operating companies. The LPSC, the FERC trial staff, and Entergy submitted briefs on exceptions in the proceeding. In May 2012 the FERC issued an order affirming the ALJ’s initial decision, or finding certain issues in that decision moot. Rehearing and clarification of FERC’s order have been requested.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 Rate Filing Based on Calendar Year 2009 Production Costs
In May 2010, Entergy filed with the FERC the 2010 rates in accordance with the FERC’s orders in the System Agreement proceeding, and supplemented the filing in September 2010. Several parties intervened in the proceeding at the FERC, including the LPSC and the City Council, which have also filed protests. In July 2010 the FERC accepted Entergy’s proposed rates for filing, effective June 1, 2010, subject to refund, and set the proceeding for hearing and settlement procedures. Settlement procedures have been terminated, and the ALJ scheduled hearings to begin in March 2011. Subsequently, in January 2011 the ALJ issued an order directing the parties and FERC Staff to show cause why this proceeding should not be stayed pending the issuance of FERC decisions in the prior production cost proceedings currently before the FERC on review. In March 2011 the ALJ issued an order placing this proceeding in abeyance.
2011 Rate Filing Based on Calendar Year 2010 Production Costs
In May 2011, Entergy filed with the FERC the 2011 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In July 2011 the FERC accepted Entergy's proposed rates for filing, effective June 1, 2011, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in the prior production cost proceedings currently before the FERC on review.
2012 Rate Filing Based on Calendar Year 2011 Production Costs
In May 2012, Entergy filed with the FERC the 2012 rates in accordance with the FERC’s orders in the System Agreement proceeding. Several parties intervened in the proceeding at the FERC, including the LPSC, which filed a protest as well. In August 2012 the FERC accepted Entergy's proposed rates for filing, effective June 2012, subject to refund, set the proceeding for hearing procedures, and then held those procedures in abeyance pending FERC decisions in prior production cost proceedings currently before the FERC on review.
Interruptible Load Proceeding
In April 2007, the U.S. Court of Appeals for the D.C. Circuit issued its opinion in the LPSC’s appeal of the FERC’s March 2004 and April 2005 orders related to the treatment under the System Agreement of the Utility operating companies’ interruptible loads. In its opinion the D.C. Circuit concluded that the FERC (1) acted arbitrarily and capriciously by allowing the Utility operating companies to phase-in the effects of the elimination of the interruptible load over a 12-month period of time; (2) failed to adequately explain why refunds could not be ordered under Section 206(c) of the Federal Power Act; and (3) exercised appropriately its discretion to defer addressing the cost of sulfur dioxide allowances until a later time. The D.C. Circuit remanded the matter to the FERC for a more considered determination on the issue of refunds. The FERC issued its order on remand in September 2007, in which it directed Entergy to make a compliance filing removing all interruptible load from the computation of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, the order directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In November 2007 the Utility operating companies filed a refund report describing the refunds to be issued pursuant to the FERC's orders. The LPSC filed a protest to the refund report in December 2007, and the Utility operating companies filed an answer to the protest in January 2008. The refunds were made in October 2008 by the Utility operating companies that owed refunds to the Utility operating companies that were due a refund under the decision. The APSC and the Utility operating companies appealed the FERC decisions to the D.C. Circuit. Because of its refund obligation to its customers as a result of this proceeding and a related LPSC proceeding, Entergy Louisiana recorded provisions during 2008 of approximately $16 million, including interest, for rate refunds. The refunds were made in the fourth quarter 2009.
Following the filing of petitioners' initial briefs, the FERC filed a motion requesting the D.C. Circuit hold the appeal of the FERC’s decisions ordering refunds in the interruptible load proceeding in abeyance and remand the record to the FERC. The D.C. Circuit granted the FERC’s unopposed motion in June 2009. In December 2009 the FERC established a paper hearing to determine whether the FERC had the authority and, if so, whether it would be appropriate to order refunds resulting from changes in the treatment of interruptible load in the allocation of capacity costs by the Utility operating companies. In August 2010 the FERC issued an order stating that it has the authority and refunds are appropriate. The APSC, MPSC, and Entergy requested rehearing of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
FERC’s decision. In June 2011 the FERC issued an order granting rehearing in part and denying rehearing in part, in which the FERC determined to invoke its discretion to deny refunds. The FERC held that in this case where “the Entergy system as a whole collected the proper level of revenue, but, as was later established, incorrectly allocated peak load responsibility among the various Entergy operating companies….the Commission will apply here our usual practice in such cases, invoking our equitable discretion to not order refunds, notwithstanding our authority to do so.” The LPSC has requested rehearing of the FERC’s June 2011 decision. On October 6, 2011 the FERC issued an “Order Establishing Paper Hearing” inviting parties that oppose refunds to file briefs within 30 days addressing the LPSC’s argument that FERC precedent supports refunds under the circumstances present in this proceeding. Parties that favor refunds were then invited to file reply briefs within 21 days of the date that the initial briefs are due. Briefs were submitted and the matter is pending.
In September 2010, the FERC had issued an order setting the refund report filed in the proceeding in November 2007 for hearing and settlement judge procedures. In May 2011, Entergy filed a settlement agreement that resolved all issues relating to the refund report set for hearing. In June 2011 the settlement judge certified the settlement as uncontested and the settlement agreement is currently pending before the FERC. In July 2011, Entergy filed an amended/corrected refund report and a motion to defer action on the settlement agreement until after the FERC rules on the LPSC’s rehearing request regarding the June 2011 decision denying refunds.
Prior to the FERC’s June 2011 order on rehearing, Entergy Arkansas filed an application in November 2010 with the APSC for recovery of the refund that it paid. The APSC denied Entergy Arkansas’s application, and also denied Entergy Arkansas’s petition for rehearing. If the FERC were to order Entergy Arkansas to pay refunds on rehearing in the interruptible load proceeding the APSC’s decision would trap FERC-approved costs at Entergy Arkansas with no regulatory-approved mechanism to recover them. In August 2011, Entergy Arkansas filed a complaint in the United States District Court for the Eastern District of Arkansas asking for a declaratory judgment that the rejection of Entergy Arkansas’s application by the APSC is preempted by the Federal Power Act. The APSC filed a motion to dismiss the complaint. In April 2012 the United States district court dismissed Entergy Arkansas’s complaint without prejudice stating that Entergy Arkansas’s claim is not ripe for adjudication and that Entergy Arkansas did not have standing to bring suit at this time.
Entergy Arkansas Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response, the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the applicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony, the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC in its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, of intra-system bills for 2003, 2004, and 2006, the three years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the potential cost for Entergy Arkansas would be up to $12 million for the years 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans' lostOrleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and decreasedcertain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.
Storm Cost Recovery Filings with Retail Regulators
Entergy Arkansas
Entergy Arkansas January 2009 Ice Storm
In January 2009 a severe ice storm caused significant damage to Entergy Arkansas's transmission and distribution lines, equipment, poles, and other facilities. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage
Entergy Corporation and Subsidiaries
Notes to Financial Statements
restoration costs. In June 2010 the APSC issued a financing order authorizing the issuance of approximately $126.3 million in storm cost recovery bonds, which includes carrying costs of $11.5 million and $4.6 million of up-front financing costs. See Note 5 to the financial statements for a discussion of the August 2010 issuance of the securitization bonds.
Entergy Arkansas December 2012 Winter Storm
In December 2012 a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for the repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas plans to present a cost recovery proposal to the APSC in a base rate case filing in March 2013.
Entergy Gulf States Louisiana and Entergy Louisiana
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy's service territory. Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings).Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.
In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana’s and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $15.5 million and $27.75 million of customer benefits, respectively, through prospective annual rate reductions of $3.1 million and $5.55 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $468.9 million in bonds under Act 55. From the $462.4 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $262.4 million to acquire 2,624,297.11 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In July 2010, the LCDA issued another $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LCDA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy Gulf States Louisiana and Entergy Louisiana do not report the collections as revenue following because they are merely acting as the billing and collection agents for the state.
Hurricane Katrina.Katrina and Hurricane Rita
In August and September 2005, Hurricanes Katrina and Rita caused catastrophic damage to large portions of the Utility’s service territories in Louisiana, Mississippi, and Texas, including the effect of extensive flooding that resulted from levee breaks in and around the greater New Orleans area. The alternativestorms and flooding resulted in widespread power outages, significant damage to electric distribution, transmission, and generation and gas infrastructure, and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.
In March 2008, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings are expected to produce additional customer benefits as compared to traditional securitization. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55 financings. On April 10, 2008, Entergy Gulf States Louisiana and Entergy
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana and Entergy Louisiana’s proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 million and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 million for five years. On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financings.
In July 2008, the LPFA issued $687.7 million in bonds under the aforementioned Act 55. From the $679 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $152 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545 million, including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
In August 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion. In February 2012, Entergy Gulf States Louisiana sold 500,000 of its Class A preferred membership units in Entergy Holdings Company LLC, a wholly-owned Entergy subsidiary, to a third party in exchange for $51 million plus accrued but unpaid distributions on the units. The 500,000 preferred membership units are mandatorily redeemable in January 2112.
Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the bonds on their balance sheets because the bonds are the obligation of the LPFA, and there is no recourse against Entergy, Entergy Gulf States Louisiana or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana and Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remit the collections to the bond indenture trustee. Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana do not report the collections as revenue because they are merely acting as the billing and collection agent for the state.
Entergy New Orleans
In December 2005, the U.S. Congress passed the Katrina Relief Bill, a hurricane aid package that included Community Development Block Grant (CDBG) funding (for the states affected by Hurricanes Katrina, Rita, and Wilma) that allowed state and local leaders to fund individual recovery priorities. In March 2007 the City Council certified that Entergy New Orleans recommended adjusts for lost customers and assumes that the City Council's June 2006 decision to allow recovery of all Grand Gulfincurred $205 million in storm-related costs through December 2006 that are eligible for CDBG funding under the fuel adjustment clause stays in place during the rate-effective period (a significant portion of Grand Gulf costs was previously recovered through base rates).
At the same time as it made its formula rate plan filings,state action plan. Entergy New Orleans also filed with the City Council a request to implement two storm-related riders. With the first rider, Entergy New Orleans sought to recover the electric and gas restoration costs that it had actually spent through March 31, 2006. Entergy New Orleans also proposed semiannual filings to update the rider for additional restoration spending and also to consider the receiptreceived $180.8 million of CDBG funds or insurance proceeds that it may receive. With the second rider, Entergy New Orleans sought to establish a storm reserve to provide for the risk of another storm.in 2007 and $19.2 million in 2010.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In October 2006, the City Council approved a rate filing settlement agreement that, resolved Entergy New Orleans' rate and storm-related rider filings by providing for phased-in rate increases, while taking into account with respect to storm restoration costs the anticipated receipt of CDBG funding as recommended by the Louisiana Recovery Authority. The settlement provided for a 0% increase in electric base rates through December 2007, with a $3.9 million increase implemented in January 2008. Recovery of all Grand Gulf costs through the fuel adjustment clause was continued. Gas base rates increased by $4.75 million in November 2006 and increased by additional $1.5 million in March 2007 and an additional $4.75 million in November 2007. The settlement called for Entergy New Orleans to file a base rate case by July 31, 2008, which it did as discussed above. The settlement agreement discontinued the formula rate plan and the generation performance-based plan but permitted Entergy New Orleans to file an application to seek authority to implement formula rate plan mechanisms no sooner than six months following the effective date of the implementation of the base rates resulting from the July 31, 2008 base rate case. The settlement alsoamong other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider beginningthat began in March 2007. These storm reserve funds will beare held in a restricted escrow account.account until needed in response to a storm. In November 2012, Entergy New Orleans withdrew $10 million from the storm reserve escrow account to partially offset the costs associated with Hurricane Isaac.
New Nuclear Generation Development Costs
Entergy Gulf States Louisiana and Entergy Louisiana
Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. The testimony and legal briefs of the LPSC staff generally support the request of Entergy Gulf States Louisiana and Entergy Louisiana, although other parties filed briefs, without supporting testimony, in opposition to the request. At an evidentiary hearing in October 2011, Entergy Gulf States Louisiana, Entergy Louisiana, and the LPSC staff presented testimony in support of certification of activities to preserve an option for a new nuclear plant at River Bend. The ALJ recommended, however, that the LPSC decline the request of Entergy Gulf States Louisiana and Entergy Louisiana on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. There has been no suggestion that the planning activities or costs incurred were imprudent. At its June 28, 2012 meeting the LPSC voted to uphold the ALJ’s decision and directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their anticipated, upcoming rate case filings, fully reserving the LPSC’s right to determine the recoverability of such costs in rates. On September 10, 2012, Entergy Gulf States Louisiana and Entergy Louisiana filed a petition for appeal and judicial review of the LPSC’s order with the Louisiana Nineteenth Judicial District Court. A schedule for the appeal has not been established. In their rate cases filed in February 2013, Entergy Gulf States Louisiana and Entergy Louisiana request recovery of their new nuclear generation development costs over a ten-year amortization period, with the costs included in rate base.
Entergy Mississippi
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi has been developing and is preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it is in the public interest to preserve the option to construct new nuclear generation at Grand Gulf and that the MPSC approve the deferral of Entergy Mississippi’s costs incurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation states that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf. The costs shall be treated as a regulatory asset until the proceeding is resolved. The Mississippi Public Utilities Staff and Entergy Mississippi also agree that the MPSC should conduct a hearing to consider the relief requested by Entergy Mississippi in its application, including evidence regarding whether costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf were prudently incurred and are otherwise allowable. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that such prudently incurred costs shall be recoverable in a manner to be determined by the MPSC. In the Stipulation, the Mississippi Public Utilities Staff and Entergy Mississippi agree that the development of a nuclear unit project
Entergy Corporation and Subsidiaries
Notes to Financial Statements
option is consistent with the Mississippi Baseload Act. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that the deferral of costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf also is consistent with the Mississippi Baseload Act. Entergy Mississippi will not accrue carrying charges or continue to accrue AFUDC on the costs, pending the outcome of the proceeding. Further proceedings before the MPSC have not been scheduled.
Texas Power Price Lawsuit
In January 2008,August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class of the Texas retail customers of Entergy New Orleans voluntarily implemented a 6.15% base rate credit (the recovery credit)Gulf States, Inc. who were billed and paid for electric customers, which returned approximately $11.3 millionpower from January 1, 1994 to electric customers in 2008. Entergy New Orleans was able to implement this credit because during 2007 the recovery of New Orleans after Hurricane Katrina was occurring faster than expected in 2006 projections. In addition, Entergy New Orleans committed to set aside $2.5 million for an energy efficiency program focused on community education and outreach and weatherization of homes.
Fuel Adjustment Clause Litigation
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans,present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy PowerArkansas. Entergy Gulf States, Inc. was not a named defendant, but was alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. Thethe lawsuit to protect its interests.
Plaintiffs allege that the defendants implemented a “price gouging accounting scheme” to sell to plaintiffs seek treble damages for alleged injuries arisingand similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council.off-system suppliers. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.
Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys’ fees, and disgorgement of profits. The plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios. The Entergy New Orleans improperly included certain costsdefendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.
The case is pending in state district court, and in March 2012 the calculation of fuel charges andcourt found that Entergy New Orleans imprudently purchased high-cost fuel or energy from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspiredcase met the requirements to make these purchasesbe maintained as a class action under Texas law. On April 30, 2012, the court entered an order certifying the class. The defendants have appealed the order to the detrimentTexas Court of Entergy New Orleans' ratepayersAppeals – First District. The appeal is pending and toproceedings in district court are stayed until the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and the FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court was stayed by stipulation of the parties and order of the court pending review of the decision by the City Council in the proceeding discussed in the next paragraph. appeal is resolved.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Plaintiffs also filed a corresponding complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. In May 2005 the Civil District Court for the Parish of Orleans affirmed the City Council resolution, finding no support for the plaintiffs' claim that the refund amount should be higher. In June 2005, the plaintiffs appealed the Civil District Court decision to the Louisiana Fourth Circuit Court of Appeal. On February 25, 2008, the Fourth Circuit Court of Appeal issued a decision affirming in part, and reversing in part, the Civil District Court's decision. Although the Fourth Circuit Court of Appeal did not reverse any of the substantive findings and conclusions of the City Council or the Civil District Court, the Fourth Circuit found that the amount of the refund was arbitrary and capricious and increased the amount of the refund to $34.3 million. Entergy New Orleans and the City Council filed with the Louisiana Supreme Court seeking, among other things, review and reversal of the Fourth Circuit decision. In April 2009 the Louisiana Supreme Court reversed the decision of the Louisiana Fourth Circuit Court of Appeal and reinstated the decision of the Civil District Court. In May 2009 the Louisiana Supreme Court denied the plaintiffs' request for rehearing. In January 2010 the plaintiffs filed a motion to lift the stay and to supplement and amend their state court petition.
In the Entergy New Orleans bankruptcy proceeding, the named plaintiffs in the Entergy New Orleans fuel clause lawsuit, together with the named plaintiffs in the Entergy New Orleans rate of return lawsuit, filed a Complaint for Declaratory Judgment asking the court to declare that Entergy New Orleans, Entergy Corporation, and Entergy Services are a single business enterprise, and, as such, are liable in solido with Entergy New Orleans for any claims asserted in the Entergy New Orleans fuel adjustment clause lawsuit and the Entergy New Orleans rate of return lawsuit, and, alternatively, that the automatic stay be lifted to permit the movants to pursue the same relief in state court. The bankruptcy court dismissed the action on April 26, 2006. The matter was appealed to the U.S. District Court for the Eastern District of Louisiana, and the district court affirmed the dismissal in October 2006, but on different grounds, concluding that the lawsuit was premature. In Entergy New Orleans' plan of reorganization that was confirmed by the bankruptcy court in May 2007, the plaintiffs' claims are treated as unimpaired "Litigation Claims," which will "ride through" the bankruptcy proceeding, with any legal, equitable and contractual rights to which the plaintiffs' Litigation Claim entitles the plaintiffs unaltered by the plan of reorganization.
Electric Industry Restructuring (Entergy Texas)
In June 2009, a law was enacted in Texas that requires Entergy Texas to cease all activities relating to Entergy Texas' transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining the Southwest Power Pool. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the new law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT's certification of Entergy Texas' power region. In response to the new law, Entergy Texas in June 2009 gave notice to the PUCT of the withdrawal of its previously filed transition to competition plan, and requested that its transition to competition proceeding be dismissed. In July 2009 the ALJ dismissed the proceeding.
The new law also contains provisions that allow Entergy Texas to be included in a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The new law further amends already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the new law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall "purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer"; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The new law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The new law provides that the PUCT shall approve, reject, or modify the proposed tariff not later than September 1, 2010.
Interruptible Load Proceeding(Entergy Louisiana)
The FERC issued orders in September 2005 and 2007 in which it directed Entergy to remove all interruptible load from certain computations of peak load responsibility commencing April 1, 2004 and to issue any necessary refunds to reflect this change. In addition, in September 2008 the FERC directed the Utility operating companies to make refunds for the period May 1995 through July 1996. In October 2009, the LPSC issued an order approving the flow through to retail rates of the LPSC-jurisdictional portion of the payments and credits resulting from the FERC's orders that had not yet been flowed through to retail rates, which required a net refund to Entergy Louisiana retail customers of $17.6 million, including interest. Of this amount, $5.4 million was refunded subject to adjustment in the event that future action by the FERC or the D.C. Circuit Court of Appeals results in a reversal or change in the amount of the refunds ordered by the FERC in September 2008.
Co-Owner-Initiated Proceeding at the FERC (Entergy Arkansas)
In October 2004, Arkansas Electric Cooperative Corporation (AECC) filed a complaint at the FERC against Entergy Arkansas relating to a contract dispute over the pricing of substitute energy at the co-owned Independence and White Bluff coal plants. The main issue in the case related to the consequences under the governing contracts when the dispatch of the coal units is constrained due to system operating conditions. A hearing was held on the AECC complaint and an ALJ Initial Decision was issued in January 2006 in which the ALJ found AECC's claims to be without merit. On October 25, 2006, the FERC issued its order in the proceeding. In the order, the FERC reversed the ALJ's findings. Specifically, the FERC found that the governing contracts do not recognize the effects of dispatch constraints on the co-owned units. The FERC explained that for over twenty-three years the course of conduct of the parties was such that AECC received its full entitlement to the two coal units, regardless of any reduced output caused by system operating constraints. Based on the order, Entergy Arkansas is required to refund to AECC all excess amounts billed to AECC as a result of the system operating constraints. The FERC denied Entergy Arkansas' request for rehearing and Entergy Arkansas refunded $22.1 million (including interest) to AECC in September 2007. Entergy Arkansas had previously recorded a provision for the estimated effect of this refund. In January 2010 the FERC issued an order conditionally accepting the refund report and ordering further refunds, noting that the refund period should have included the period July 1, 2004 through December 23, 2004. Entergy Arkansas had previously recorded a provision for the estimated effect of this refund.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Income tax expensestaxes from continuing operations for 2009, 2008,2012, 2011, and 20072010 for Entergy Corporation and subsidiariesSubsidiaries consist of the following:
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| Current: | | | | | | | | | |
| Federal | | $ | (47,851 | ) | | $ | 452,713 | | | $ | 145,161 | |
| Foreign | | | 143 | | | | 130 | | | | 131 | |
| State | | | (41,516 | ) | | | 152,711 | | | | 19,313 | |
| Total | | | (89,224 | ) | | | 605,554 | | | | 164,605 | |
| Deferred and non-current - net | | | 131,130 | | | | (311,708 | ) | | | 468,698 | |
| Investment tax credit | | | | | | | | | | | | |
| adjustments - net | | | (11,051 | ) | | | (7,583 | ) | | | (16,064 | ) |
| Income tax expense from | | | | | | | | | | | | |
| continuing operations | | $ | 30,855 | | | $ | 286,263 | | | $ | 617,239 | |
| | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | |
| Current: | | | | | | | | | |
| Federal | | $ | (433,105 | ) | | $ | 451,517 | | | $ | (1,379,288 | ) |
| Foreign | | | 154 | | | | 256 | | | | 316 | |
| State | | | (108,552 | ) | | | 146,171 | | | | 27,174 | |
| Total | | | (541,503 | ) | | | 597,944 | | | | (1,351,798 | ) |
| Deferred and non-current -- net | | | 1,191,418 | | | | 23,022 | | | | 1,884,383 | |
| Investment tax credit | | | | | | | | | | | | |
| adjustments -- net | | | (17,175 | ) | | | (17,968 | ) | | | (18,168 | ) |
| Income tax expense from | | | | | | | | | | | | |
| continuing operations | | $ | 632,740 | | | $ | 602,998 | | | $ | 514,417 | |
| | | | | | | | | | | | | |
Income tax expensestaxes for 2009, 2008,2012, 2011, and 20072010 for Entergy'sEntergy’s Registrant Subsidiaries consist of the following:
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2012 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| Current: | | | | | | | | | | | | | | | | | | | | | |
| Federal | | $ | 64,069 | | | $ | (66,081 | ) | | $ | (132,999 | ) | | $ | 3,188 | | | $ | (9,484 | ) | | $ | (114,677 | ) | | $ | (50,491 | ) |
| State | | | 6,712 | | | | 9,535 | | | | (1,269 | ) | | | (4,425 | ) | | | (1,617 | ) | | | 4,933 | | | | (8,544 | ) |
| Total | | | 70,781 | | | | (56,546 | ) | | | (134,268 | ) | | | (1,237 | ) | | | (11,101 | ) | | | (109,744 | ) | | | (59,035 | ) |
| Deferred and non-current - net | | | 26,042 | | | | 112,390 | | | | 8,463 | | | | 59,045 | | | | 18,586 | | | | 144,471 | | | | 137,832 | |
| Investment tax credit | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| adjustments - net | | | (2,017 | ) | | | (3,228 | ) | | | (3,117 | ) | | | 871 | | | | (245 | ) | | | (1,609 | ) | | | (1,682 | ) |
| Income taxes | | $ | 94,806 | | | $ | 52,616 | | | $ | (128,922 | ) | | $ | 58,679 | | | $ | 7,240 | | | $ | 33,118 | | | $ | 77,115 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2009 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | | | |
| Federal | | ($37,544) | | ($203,651) | | $12,387 | | $19,347 | | $160,846 | | ($72,207) | | $73,183 |
| State | | 22,710 | | (12,416) | | (49,843) | | (2,321) | | 1,171 | | 2,478 | | (12,667) |
| Total | | (14,834) | | (216,067) | | (37,456) | | 17,026 | | 162,017 | | (69,729) | | 60,516 |
| Deferred and non-current -- net | | 100,584 | | 308,659 | | 85,728 | | 26,400 | | (145,981) | | 108,253 | | 39,866 |
| Investment tax credit | | | | | | | | | | | | | | |
| adjustments - net | | (3,994) | | (3,407) | | (3,222) | | (1,103) | | (323) | | (1,609) | | (3,481) |
| Recorded income tax expense | | | | | | | | | | | | | | |
2008 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| | | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2011 | | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | | (In Thousands) | |
| Current: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | | ($200,032) | | $96,585 | | $335,164 | | $43,214 | | $22,419 | | $73,974 | | 25,356 | | $ | (12,448 | ) | | $ | (30,106 | ) | | $ | (136,800 | ) | | $ | (9,466 | ) | | $ | 14,641 | | | $ | (33,045 | ) | | $ | 139,529 | |
| State | | 12,533 | | 39,423 | | 59,304 | | 5,099 | | (3,493) | | 3,954 | | 8,518 | | | (1,751 | ) | | | 15,950 | | | | 34,832 | | | | 6,069 | | | | 1,724 | | | | 3,153 | | | | 16,825 | |
| Total | | (187,499) | | 136,008 | | 394,468 | | 48,313 | | 18,926 | | 77,928 | | 33,874 | | | (14,199 | ) | | | (14,156 | ) | | | (101,968 | ) | | | (3,397 | ) | | | 16,365 | | | | (29,892 | ) | | | 156,354 | |
| Deferred and non-current -- net | | 288,118 | | (74,681) | | (320,596) | | (13,918) | | 4,471 | | (48,200) | | 29,100 | |
| Deferred and non-current - net | | | | 148,978 | | | | 107,250 | | | | (265,046 | ) | | | 32,380 | | | | (201 | ) | | | 80,993 | | | | (84,505 | ) |
| Investment tax credit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| adjustments - net | | (3,996) | | (4,130) | | (3,224) | | (1,155) | | (345) | | (1,610) | | (3,480) | | | (2,014 | ) | | | (3,358 | ) | | | (3,197 | ) | | | (182 | ) | | | (302 | ) | | | (1,609 | ) | | | 3,104 | |
| Recorded income tax expense | | $96,623 | | $57,197 | | $70,648 | | $33,240 | | $23,052 | | $28,118 | | $59,494 | |
| Income taxes | | | $ | 132,765 | | | $ | 89,736 | | | $ | (370,211 | ) | | $ | 28,801 | | | $ | 15,862 | | | $ | 49,492 | | | $ | 74,953 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2007 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | | | |
| Federal | | ($464,280) | | ($306,133) | | $153,083 | | ($49,810) | | ($20,779) | | ($280,094) | | ($273,310) |
| State | | 13,173 | | 14,454 | | 35,884 | | 8,576 | | 1,663 | | 6,061 | | 2,463 |
| Total | | (451,107) | | (291,679) | | 188,967 | | (41,234) | | (19,116) | | (274,033) | | (270,847) |
| Deferred and non-current -- net | | 540,750 | | 421,149 | | (102,246) | | 78,397 | | 32,978 | | 311,863 | | 319,773 |
| Investment tax credit | | | | | | | | | | | | | | |
| adjustments - net | | (4,005) | | (5,769) | | (3,227) | | (1,313) | | (356) | | (1,581) | | (3,479) |
| Recorded income tax expense | | $85,638 | | $123,701 | | $83,494 | | $35,850 | | $13,506 | | $36,249 | | $45,447 |
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2010 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| Current: | | | | | | | | | | | | | | | | | | | | | |
| Federal | | $ | 114,821 | | | $ | 196,230 | | | $ | 73,174 | | | $ | 13,722 | | | $ | (114,382 | ) | | $ | (10,607 | ) | | $ | (4,102 | ) |
| State | | | (9,200 | ) | | | 481 | | | | (4,324 | ) | | | 5,959 | | | | 1,427 | | | | 1,060 | | | | 3,328 | |
| Total | | | 105,621 | | | | 196,711 | | | | 68,850 | | | | 19,681 | | | | (112,955 | ) | | | (9,547 | ) | | | (774 | ) |
| Deferred and non-current - net | | | 10,328 | | | | (101,007 | ) | | | 918 | | | | 31,415 | | | | 129,880 | | | | 53,539 | | | | 60,305 | |
| Investment tax credit | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| adjustments - net | | | (3,005 | ) | | | (3,407 | ) | | | (3,222 | ) | | | (985 | ) | | | (324 | ) | | | (1,609 | ) | | | (3,482 | ) |
| Income taxes | | $ | 112,944 | | | $ | 92,297 | | | $ | 66,546 | | | $ | 50,111 | | | $ | 16,601 | | | $ | 42,383 | | | $ | 56,049 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Total income taxes for Entergy Corporation and subsidiariesSubsidiaries differ from the amounts computed by applying the statutory income tax rate to income before income taxes. The reasons for the differences for the years 2009, 2008,2012, 2011, and 20072010 are:
| | | 2009 | | | 2008 | | | 2007 | | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | | | | | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | |
| Net income attributable to Entergy Corporation | | $ | 1,231,092 | | | $ | 1,220,566 | | | $ | 1,134,849 | | | $ | 846,673 | | | $ | 1,346,439 | | | $ | 1,250,242 | |
| Preferred dividend requirements of subsidiaries | | | 19,958 | | | | 19,969 | | | | 25,105 | | | | 21,690 | | | | 20,933 | | | | 20,063 | |
| Consolidated net income | | | 1,251,050 | | | | 1,240,535 | | | | 1,159,954 | | | | 868,363 | | | | 1,367,372 | | | | 1,270,305 | |
| Income taxes | | | 632,740 | | | | 602,998 | | | | 514,417 | | | | 30,855 | | | | 286,263 | | | | 617,239 | |
| Income before income taxes | | $ | 1,883,790 | | | $ | 1,843,533 | | | $ | 1,674,371 | | | $ | 899,218 | | | $ | 1,653,635 | | | $ | 1,887,544 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 659,327 | | | $ | 645,237 | | | $ | 586,030 | | | $ | 314,726 | | | $ | 578,772 | | | $ | 660,640 | |
| Increases (reductions) in tax resulting from: | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of federal income tax effect | | | 65,241 | | | | 9,926 | | | | 31,066 | | | | 40,699 | | | | 93,940 | | | | 40,530 | |
| Regulatory differences - utility plant items | | | 57,383 | | | | 45,543 | | | | 50,070 | | | | 35,527 | | | | 39,970 | | | | 31,473 | |
| Equity component of AFUDC | | | | (30,838 | ) | | | (30,184 | ) | | | (16,542 | ) |
| Amortization of investment tax credits | | | (16,745 | ) | | | (17,458 | ) | | | (17,612 | ) | | | (14,000 | ) | | | (14,962 | ) | | | (15,980 | ) |
| Decommissioning trust fund basis | | | (7,917 | ) | | | (417 | ) | | | (35,684 | ) | |
| Capital gains (losses) | | | (28,051 | ) | | | (74,278 | ) | | | 7,126 | | |
| Flow-through/permanent differences | | | (49,486 | ) | | | 14,656 | | | | (49,609 | ) | |
| Tax reserves | | | (17,435 | ) | | | (27,970 | ) | | | (25,821 | ) | |
| Valuation allowance | | | (40,795 | ) | | | 11,770 | | | | (8,676 | ) | |
| Flow-through / permanent differences | | | | (14,801 | ) | | | (17,848 | ) | | | (26,370 | ) |
| Net-of-tax regulatory liability (a) | | | | (4,356 | ) | | | 65,357 | | | | - | |
| Deferred tax reversal on PPA settlement (a) | | | | - | | | | (421,819 | ) | | | - | |
| Deferred tax asset on additional depreciation (b) | | | | (155,300 | ) | | | - | | | | - | |
| Write-off of reorganization costs | | | | - | | | | - | | | | (19,974 | ) |
| Tax law change-Medicare Part D | | | | - | | | | - | | | | 13,616 | |
| Write-off of regulatory asset for income taxes | | | | 42,159 | | | | - | | | | - | |
| Capital losses | | | | (20,188 | ) | | | - | | | | - | |
| Provision for uncertain tax positions (c) | | | | (159,957 | ) | | | 2,698 | | | | (43,115 | ) |
| Other - net | | | 11,218 | | | | (4,011 | ) | | | (22,473 | ) | | | (2,816 | ) | | | (9,661 | ) | | | (7,039 | ) |
| Total income taxes as reported | | $ | 632,740 | | | $ | 602,998 | | | $ | 514,417 | | | $ | 30,855 | | | $ | 286,263 | | | $ | 617,239 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 33.6 | % | | | 32.7 | % | | | 30.7 | % | | | 3.4 | % | | | 17.3 | % | | | 32.7 | % |
| | | | | | | | | | | | | | |
(a) See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items. |
(b) See "Income Tax Audits - 2004-2005 IRS Audit" below for discussion of this item. |
(c) See "Income Tax Audits - 2008-2009 IRS Audit" below for discussion of the most significant item in 2012. |
In December 2009 an Entergy subsidiary sold Class B preferred shares to a third party for $2.1 million. The sale resulted in a capital loss for tax purposes of $73.1 million, providing a federal and state net tax benefit of approximately $28 million that Entergy recorded in the fourth quarter 2009. This amount is included in capital losses in the table above.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total income taxes for the Registrant Subsidiaries differ from the amounts computed by applying the statutory income tax rate to income before taxes. The reasons for the differences for the years 2009, 2008,2012, 2011, and 20072010 are:
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2009 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 66,875 | | | $ | 153,047 | | | $ | 232,845 | | | $ | 77,636 | | | $ | 31,025 | | | $ | 63,841 | | | $ | 48,908 | |
| Income taxes | | | 81,756 | | | | 89,185 | | | | 45,050 | | | | 42,323 | | | | 15,713 | | | | 36,915 | | | | 96,901 | |
| Pretax income | | $ | 148,631 | | | $ | 242,232 | | | $ | 277,895 | | | $ | 119,959 | | | $ | 46,738 | | | $ | 100,756 | | | $ | 145,809 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 52,021 | | | $ | 84,781 | | | $ | 97,263 | | | $ | 41,986 | | | $ | 16,358 | | | $ | 35,264 | | | $ | 51,033 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 9,617 | | | | 6,487 | | | | 5,095 | | | | 2,417 | | | | 1,387 | | | | 1,509 | | | | 4,033 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 19,275 | | | | 10,303 | | | | 14,463 | | | | 1,365 | | | | (55 | ) | | | 2,008 | | | | 10,024 | |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (3,972 | ) | | | (3,088 | ) | | | (3,192 | ) | | | (1,092 | ) | | | (324 | ) | | | (1,596 | ) | | | (3,480 | ) |
| Flow-through/permanent | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | 2,331 | | | | (7,317 | ) | | | (26,614 | ) | | | (319 | ) | | | (2,300 | ) | | | (1,538 | ) | | | (4,462 | ) |
| Benefit of Entergy Corporation | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| expenses | | | 978 | | | | (170 | ) | | | (24,231 | ) | | | (2,841 | ) | | | 31 | | | | - | | | | 35,027 | |
| Taxes reserves | | | - | | | | (5,400 | ) | | | (17,700 | ) | | | 800 | | | | (400 | ) | | | 600 | | | | 4,900 | |
| Other -- net | | | 1,506 | | | | 3,589 | | | | (34 | ) | | | 7 | | | | 1,016 | | | | 668 | | | | (174 | ) |
| Total income taxes | | $ | 81,756 | | | $ | 89,185 | | | $ | 45,050 | | | $ | 42,323 | | | $ | 15,713 | | | $ | 36,915 | | | $ | 96,901 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 55.0 | % | | | 36.8 | % | | | 16.2 | % | | | 35.3 | % | | | 33.6 | % | | | 36.6 | % | | | 66.5 | % |
The flow-through/permanent difference for Entergy Louisiana relates to the exclusion of dividend income from its preferred membership interest in Entergy Holdings Company, LLC as well as the flow-through of the equity component of AFUDC.
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2012 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 152,365 | | | $ | 158,977 | | | $ | 281,081 | | | $ | 46,768 | | | $ | 17,065 | | | $ | 41,971 | | | $ | 111,866 | |
| Income taxes (benefit) | | | 94,806 | | | | 52,616 | | | | (128,922 | ) | | | 58,679 | | | | 7,240 | | | | 33,118 | | | | 77,115 | |
| Pretax income | | $ | 247,171 | | | $ | 211,593 | | | $ | 152,159 | | | $ | 105,447 | | | $ | 24,305 | | | $ | 75,089 | | | $ | 188,981 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 86,510 | | | $ | 74,058 | | | $ | 53,256 | | | $ | 36,906 | | | $ | 8,507 | | | $ | 26,281 | | | $ | 66,143 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 11,282 | | | | 5,087 | | | | 1,976 | | | | 3,944 | | | | 505 | | | | 3,115 | | | | 6,652 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 6,778 | | | | 8,472 | | | | 312 | | | | 2,619 | | | | 2,289 | | | | 3,668 | | | | 11,389 | |
| Equity component of AFUDC | | | (2,495 | ) | | | (3,042 | ) | | | (12,919 | ) | | | (1,383 | ) | | | (276 | ) | | | (1,587 | ) | | | (9,136 | ) |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (1,992 | ) | | | (3,204 | ) | | | (3,089 | ) | | | (264 | ) | | | (240 | ) | | | (1,596 | ) | | | (3,480 | ) |
| Flow-through / permanent | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | 3,427 | | | | (7,646 | ) | | | 1,397 | | | | 1,961 | | | | (4,385 | ) | | | 1,585 | | | | (357 | ) |
| Net-of-tax regulatory liability (a) | | | - | | | | - | | | | (4,356 | ) | | | - | | | | - | | | | - | | | | - | |
| Non-taxable dividend income | | | - | | | | (9,836 | ) | | | (27,336 | ) | | | - | | | | - | | | | - | | | | - | |
| Expense (benefit) of Entergy | | | | | | | | | | | | | | | | | | | | | | | | | |
| Corporation expenses | | | (19,403 | ) | | | (17,703 | ) | | | - | | | | 14,449 | | | | 2,758 | | | | - | | | | (10,241 | ) |
| Provision for uncertain | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax positions (b) | | | 11,227 | | | | 8,745 | | | | (143,583 | ) | | | 870 | | | | (2,095 | ) | | | 1,651 | | | | 17,966 | |
| Change in regulatory recovery | | | - | | | | (553 | ) | | | 7,854 | | | | - | | | | - | | | | - | | | | - | |
| Other - net | | | (528 | ) | | | (1,762 | ) | | | (2,434 | ) | | | (423 | ) | | | 177 | | | | 1 | | | | (1,821 | ) |
| Total income taxes | | $ | 94,806 | | | $ | 52,616 | | | $ | (128,922 | ) | | $ | 58,679 | | | $ | 7,240 | | | $ | 33,118 | | | $ | 77,115 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 38.4 | % | | | 24.9 | % | | | -84.7 | % | | | 55.6 | % | | | 29.8 | % | | | 44.1 | % | | | 40.8 | % |
(a) See "Income Tax Audits - 2006-2007 IRS Audit" below for discussion of these items. |
(b) See "Income Tax Audits - 2008-2009 IRS Audit" below for discussion of the most significant item in 2012. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2008 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 47,152 | | | $ | 144,767 | | | $ | 157,543 | | | $ | 59,710 | | | $ | 34,947 | | | $ | 57,895 | | | $ | 91,067 | |
| Income taxes | | | 96,623 | | | | 57,197 | | | | 70,648 | | | | 33,240 | | | | 23,052 | | | | 28,118 | | | | 59,494 | |
| Pretax income | | $ | 143,775 | | | $ | 201,964 | | | $ | 228,191 | | | $ | 92,950 | | | $ | 57,999 | | | $ | 86,013 | | | $ | 150,561 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 50,321 | | | $ | 70,687 | | | $ | 79,867 | | | $ | 32,533 | | | $ | 20,299 | | | $ | 30,105 | | | $ | 52,696 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 10,754 | | | | (891 | ) | | | (18,486 | ) | | | 4,126 | | | | 2,057 | | | | 3,138 | | | | 5,604 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 17,542 | | | | 3,308 | | | | 9,960 | | | | 3,305 | | | | 1,202 | | | | 1,076 | | | | 9,150 | |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (3,972 | ) | | | (3,730 | ) | | | (3,192 | ) | | | (1,140 | ) | | | (348 | ) | | | (1,596 | ) | | | (3,480 | ) |
| Flow-through/permanent | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | 17,868 | | | | (12,130 | ) | | | 1,553 | | | | (4,068 | ) | | | (694 | ) | | | (4,133 | ) | | | (1,956 | ) |
Benefit of Entergy Corporation expenses | | | - | | | | - | | | | - | | | | (1,556 | ) | | | - | | | | | | | | (3,420 | ) |
| Tax reserves | | | 2,800 | | | | 1,000 | | | | 1,150 | | | | 700 | | | | 200 | | | | (1,200 | ) | | | 900 | |
| Other – net | | | 1,310 | | | | (1,047 | ) | | | (204 | ) | | | (660 | ) | | | 336 | | | | 728 | | | | - | |
| Total income taxes | | $ | 96,623 | | | $ | 57,197 | | | $ | 70,648 | | | $ | 33,240 | | | $ | 23,052 | | | $ | 28,118 | | | $ | 59,494 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 67.2 | % | | | 28.3 | % | | | 31.0 | % | | | 35.8 | % | | | 39.7 | % | | | 32.7 | % | | | 39.5 | % |
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2011 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 164,891 | | | $ | 201,604 | | | $ | 473,923 | | | $ | 108,729 | | | $ | 35,976 | | | $ | 80,845 | | | $ | 64,197 | |
| Income taxes (benefit) | | | 132,765 | | | | 89,736 | | | | (370,211 | ) | | | 28,801 | | | | 15,862 | | | | 49,492 | | | | 74,953 | |
| Pretax income | | $ | 297,656 | | | $ | 291,340 | | | $ | 103,712 | | | $ | 137,530 | | | $ | 51,838 | | | $ | 130,337 | | | $ | 139,150 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 104,180 | | | $ | 101,969 | | | $ | 36,299 | | | $ | 48,136 | | | $ | 18,143 | | | $ | 45,618 | | | $ | 48,703 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 13,727 | | | | 9,618 | | | | 943 | | | | 3,211 | | | | 3,350 | | | | 2,033 | | | | 4,436 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 10,079 | | | | 8,379 | | | | 1,404 | | | | 2,038 | | | | 3,860 | | | | 4,003 | | | | 10,207 | |
| Equity component of AFUDC | | | (3,363 | ) | | | (3,181 | ) | | | (11,315 | ) | | | (2,963 | ) | | | (215 | ) | | | (1,322 | ) | | | (7,825 | ) |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (1,992 | ) | | | (3,336 | ) | | | (3,168 | ) | | | (960 | ) | | | (295 | ) | | | (1,596 | ) | | | (3,480 | ) |
| Net-of-tax regulatory liability (a) | | | - | | | | - | | | | 65,357 | | | | - | | | | - | | | | - | | | | - | |
| Deferred tax reversal on PPA | | | | | | | | | | | | | | | | | | | | | | | | | |
| settlement (a) | | | - | | | | - | | | | (421,819 | ) | | | - | | | | - | | | | - | | | | - | |
| Flow-through / permanent | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | (1,365 | ) | | | 587 | | | | (1,285 | ) | | | 304 | | | | (4,983 | ) | | | 88 | | | | 529 | |
| Non-taxable | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| dividend income | | | - | | | | (11,364 | ) | | | (27,336 | ) | | | - | | | | - | | | | - | | | | - | |
| Expense (benefit) of Entergy | | | | | | | | | | | | | | | | | | | | | | | | | |
| Corporation expenses | | | - | | | | (5,694 | ) | | | - | | | | (21,248 | ) | | | (6,235 | ) | | | (16 | ) | | | 16,559 | |
| Provision for uncertain | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax positions | | | 12,016 | | | | (7,144 | ) | | | (4,880 | ) | | | (2 | ) | | | 2,241 | | | | 717 | | | | 5,878 | |
| Other -- net | | | (517 | ) | | | (98 | ) | | | (4,411 | ) | | | 285 | | | | (4 | ) | | | (33 | ) | | | (54 | ) |
| Total income taxes | | $ | 132,765 | | | $ | 89,736 | | | $ | (370,211 | ) | | $ | 28,801 | | | $ | 15,862 | | | $ | 49,492 | | | $ | 74,953 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 44.6 | % | | | 30.8 | % | | | -357.0 | % | | | 20.9 | % | | | 30.6 | % | | | 38.0 | % | | | 53.9 | % |
The flow-through/permanent differences(a) See "Income Tax Audits - 2006-2007 IRS Audit" below for Entergy Arkansas in 2008 result from the write-offdiscussion of regulatory assets associated with storm reserve costs, lease termination removal costs, and stock-based compensation which are no longer probable of recovery. The flow-through/permanent differences for Entergy Gulf States Louisiana in 2008 result mainly from regulatory and tax accounting applied to its pension payments.these items.
2007 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 139,111 | | | $ | 192,779 | | | $ | 143,337 | | | $ | 72,106 | | | $ | 24,582 | | | $ | 58,921 | | | $ | 136,081 | |
| Income taxes | | | 85,638 | | | | 123,701 | | | | 83,494 | | | | 35,850 | | | | 13,506 | | | | 36,249 | | | | 45,447 | |
| Pretax income | | $ | 224,749 | | | $ | 316,480 | | | $ | 226,831 | | | $ | 107,956 | | | $ | 38,088 | | | $ | 95,170 | | | $ | 181,528 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 78,662 | | | $ | 110,768 | | | $ | 79,391 | | | $ | 37,785 | | | $ | 13,331 | | | $ | 33,310 | | | $ | 63,534 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 10,651 | | | | 8,294 | | | | 9,718 | | | | 3,513 | | | | 1,486 | | | | 3,739 | | | | 6,497 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 18,109 | | | | 15,688 | | | | 9,828 | | | | 125 | | | | 1,058 | | | | 1,122 | | | | 9,675 | |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (3,984 | ) | | | (5,314 | ) | | | (3,192 | ) | | | (1,296 | ) | | | (346 | ) | | | (1,621 | ) | | | (3,480 | ) |
| Flow-through/permanent | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | (14,502 | ) | | | (5,993 | ) | | | (7,495 | ) | | | (2,400 | ) | | | (906 | ) | | | (1,012 | ) | | | (3,165 | ) |
Benefit of Entergy Corporation expenses | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | (28,943 | ) |
| Other – net | | | (3,298 | ) | | | 258 | | | | (4,756 | ) | | | (1,877 | ) | | | (1,117 | ) | | | 711 | | | | 1,329 | |
| Total income taxes | | $ | 85,638 | | | $ | 123,701 | | | $ | 83,494 | | | $ | 35,850 | | | $ | 13,506 | | | $ | 36,249 | | | $ | 45,447 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 38.1 | % | | | 39.1 | % | | | 36.8 | % | | | 33.2 | % | | | 35.5 | % | | | 38.1 | % | | | 25.0 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2010 | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Net income | | $ | 172,618 | | | $ | 174,319 | | | $ | 231,435 | | | $ | 85,377 | | | $ | 31,114 | | | $ | 66,200 | | | $ | 82,624 | |
| Income taxes | | | 112,944 | | | | 92,297 | | | | 66,546 | | | | 50,111 | | | | 16,601 | | | | 42,383 | | | | 56,049 | |
| Pretax income | | $ | 285,562 | | | $ | 266,616 | | | $ | 297,981 | | | $ | 135,488 | | | $ | 47,715 | | | $ | 108,583 | | | $ | 138,673 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Computed at statutory rate (35%) | | $ | 99,947 | | | $ | 93,316 | | | $ | 104,293 | | | $ | 47,421 | | | $ | 16,700 | | | $ | 38,004 | | | $ | 48,536 | |
| Increases (reductions) in tax | | | | | | | | | | | | | | | | | | | | | | | | | |
| resulting from: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| State income taxes net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| federal income tax effect | | | 13,156 | | | | 1,142 | | | | (10,618 | ) | | | 1,245 | | | | 1,387 | | | | 424 | | | | 2,206 | |
| Regulatory differences - | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| utility plant items | | | 6,126 | | | | (4,004 | ) | | | 7,374 | | | | 3,455 | | | | 3,999 | | | | 4,089 | | | | 10,435 | |
| Equity component of AFUDC | | | (144 | ) | | | (1,547 | ) | | | (8,361 | ) | | | (1,643 | ) | | | (184 | ) | | | (1,525 | ) | | | (3,138 | ) |
| Amortization of investment | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax credits | | | (2,983 | ) | | | (3,309 | ) | | | (3,192 | ) | | | (972 | ) | | | (313 | ) | | | (1,596 | ) | | | (3,480 | ) |
| Flow-through / permanent | | | | | | | | | | | | | | | | | | | | | | | | | |
| differences | | | (1,235 | ) | | | 8,423 | | | | (754 | ) | | | 153 | | | | (4,883 | ) | | | 236 | | | | (497 | ) |
| Non-taxable | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| dividend income | | | - | | | | (9,189 | ) | | | (23,603 | ) | | | - | | | | - | | | | - | | | | - | |
| Provision for uncertain | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax positions | | | (2,100 | ) | | | 7,200 | | | | 2,200 | | | | 700 | | | | (300 | ) | | | 2,800 | | | | 2,090 | |
| Other -- net | | | 177 | | | | 265 | | | | (793 | ) | | | (248 | ) | | | 195 | | | | (49 | ) | | | (103 | ) |
| Total income taxes | | $ | 112,944 | | | $ | 92,297 | | | $ | 66,546 | | | $ | 50,111 | | | $ | 16,601 | | | $ | 42,383 | | | $ | 56,049 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Effective Income Tax Rate | | | 39.6 | % | | | 34.6 | % | | | 22.3 | % | | | 37.0 | % | | | 34.8 | % | | | 39.0 | % | | | 40.4 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and subsidiariesSubsidiaries as of December 31, 20092012 and 20082011 are as follows:
| | | | 2012 | | | 2011 | |
| | | 2009 | | | 2008 | | | (In Thousands) | |
| Deferred tax liabilities: | | | | | | | | | | | | |
| Plant-related basis differences | | $ | (5,476,972 | ) | | $ | (5,269,579 | ) | |
| Net regulatory assets/(liabilities) | | | (950,354 | ) | | | (1,026,203 | ) | |
| Plant basis differences - net | | | $ | (8,240,342 | ) | | $ | (7,043,758 | ) |
| Regulatory assets | | | | (898,143 | ) | | | (930,370 | ) |
| Nuclear decommissioning trusts | | | | (848,918 | ) | | | (553,558 | ) |
| Combined unitary state taxes | | | | (233,210 | ) | | | (227,427 | ) |
| Power purchase agreements | | | (862,322 | ) | | | (773,606 | ) | | | - | | | | (17,138 | ) |
| Nuclear decommissioning trusts | | | (855,608 | ) | | | (658,379 | ) | |
| Other | | | (456,053 | ) | | | (350,250 | ) | | | (485,550 | ) | | | (402,097 | ) |
| Total | | | (8,601,309 | ) | | | (8,078,017 | ) | | | (10,706,163 | ) | | | (9,174,348 | ) |
| | | | | | | | | | | | | | | | | |
| Deferred tax assets: | | | | | | | | | | | | | | | | |
| Accumulated deferred investment | | | | | | | | | |
| tax credit | | | 118,587 | | | | 123,810 | | |
| Pension-related items | | | 356,284 | | | | 391,702 | | |
| Nuclear decommissioning liabilities | | | 313,648 | | | | 239,814 | | | | 733,103 | | | | 612,945 | |
| Regulatory liabilities | | | | 404,852 | | | | 197,554 | |
| Pension and other post-employment benefits | | | | 358,893 | | | | 315,134 | |
| Sale and leaseback | | | 260,934 | | | | 252,479 | | | | 195,074 | | | | 217,430 | |
| Reserve for regulatory adjustments | | | 103,403 | | | | 106,302 | | |
| General contingencies reserve | | | 98,514 | | | | 27,268 | | |
| Unbilled/deferred revenues | | | 31,995 | | | | 27,841 | | |
| Customer deposits | | | 13,073 | | | | 76,559 | | |
| Accumulated deferred investment tax credit | | | | 110,690 | | | | 108,338 | |
| Provision for contingencies | | | | 61,576 | | | | 28,504 | |
| Power purchase agreements | | | | 43,717 | | | | - | |
| Net operating loss carryforwards | | | 148,979 | | | | 387,405 | | | | 960,235 | | | | 253,518 | |
| Capital losses | | | 45,787 | | | | 131,690 | | | | 13,631 | | | | 12,995 | |
| Valuation allowance | | | | (86,881 | ) | | | (85,615 | ) |
| Other | | | 160,264 | | | | 126,470 | | | | 141,592 | | | | 160,620 | |
| Valuation allowance | | | (47,998 | ) | | | (75,502 | ) | |
| Total | | | 1,603,470 | | | | 1,815,838 | | | | 2,936,482 | | | | 1,821,423 | |
| | | | | | | | | | | | | | | | | |
| Noncurrent accrued taxes (including unrecognized | | | | | | | | | Noncurrent accrued taxes (including unrecognized | | | | | |
| tax benefits) | | | (473,064 | ) | | | (296,284 | ) | | | (210,534 | ) | | | (814,597 | ) |
| | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | $ | (7,470,903 | ) | | $ | (6,558,463 | ) | | $ | (7,980,215 | ) | | $ | (8,167,522 | ) |
| | | | | | | | | | |
Entergy’s estimated tax attributeattributes carryovers and their expiration dates as of December 31, 2009,2012 are as follows:
| Carryover Description | | Carryover Amount | | Year(s) of expiration |
| | | | | |
| Federal net operating losses | | $8.912.6 billion | | 2023-20292028-2032 |
| State net operating losses | | $7.611.2 billion | | 2010-20292013-2032 |
FederalState capital losses | | $165177 million | | 2013-20142013-2015 |
Federal minimum tax credits | | $29 million | | never |
OtherMiscellaneous federal and state credits | | $4581.9 million | | 2023-20292013-2032 |
The $3 billion cash benefit of the federal net operating loss, less appropriate deposits for uncertain tax positions, is expected to be realized over the next six years.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers, tax credit carryovers, and other tax attributes reflected on income tax returns. The deferred tax assets recorded on the operating and capital loss carryovers are approximately $149.6 million and $45.8 million, respectively.
Because it is more likely than not that the benefit from certain state net operating and capital loss carryovers will not be utilized, a valuation allowance of $47$69.6 million and $13.6 million has been provided on the deferred tax assets relating to these state net operating and capital loss carryovers, has been provided.respectively.
Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 20092012 and 20082011 are as follows:
| | | | | Entergy | | | | | | | | | | | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | Gulf States | | Entergy | | Entergy | | Entergy | | Entergy | | System | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2009 | | Arkansas | | Louisiana | | Louisiana | | Mississippi | | New Orleans | | Texas | | Energy | |
| 2012 | | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant-related basis differences - net | | ($987,968) | | ($1,057,746) | | ($981,938) | | ($492,769) | | ($122,429) | | ($756,898) | | ($278,973) | |
| Net regulatory assets/(liabilities) | | (119,783) | | (316,969) | | (187,719) | | (38,995) | | 55,457 | | (104,312) | | (238,033) | |
| Power purchase agreements | | (46,244) | | 37,995 | | (477,965) | | 1,059 | | 60,705 | | (36,898) | | 25,192 | |
| Plant basis differences - net | | | $ | (1,565,988 | ) | | $ | (1,268,164 | ) | | $ | (1,544,256 | ) | | $ | (727,442 | ) | | $ | (202,496 | ) | | $ | (770,084 | ) | | $ | (759,896 | ) |
| Regulatory assets | | | | (172,915 | ) | | | (100,578 | ) | | | (249,051 | ) | | | (27,077 | ) | | | (4,790 | ) | | | (220,417 | ) | | | (119,209 | ) |
| Nuclear decommissioning trusts | | (198,301) | | (58,100) | | (12,369) | | - | | - | | - | | (88,646) | | | (67,025 | ) | | | (25,472 | ) | | | (29,493 | ) | | | - | | | | - | | | | - | | | | (27,809 | ) |
| Deferred fuel | | 2,948 | | (3,416) | | (2,876) | | - | | - | | 2,627 | | (21) | | | (50,068 | ) | | | (1,618 | ) | | | (11,815 | ) | | | (11,332 | ) | | | (976 | ) | | | 3,932 | | | | (445 | ) |
| Other | | (139,501) | | (3,647) | | (38,442) | | (21,763) | | (32,331) | | (19,923) | | (14,621) | | | (55,000 | ) | | | (27,501 | ) | | | (92,433 | ) | | | (12,641 | ) | | | (10,576 | ) | | | (23,681 | ) | | | (6,592 | ) |
| Total | | ($1,488,849) | | ($1,401,883) | | ($1,701,309) | | ($552,468) | | ($38,598) | | ($915,404) | | ($595,102) | | $ | (1,910,996 | ) | | $ | (1,423,333 | ) | | $ | (1,927,048 | ) | | $ | (778,492 | ) | | $ | (218,838 | ) | | $ | (1,010,250 | ) | | $ | (913,951 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred tax assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred investment | | | | | | | | | | | | | | | |
| tax credits | | 18,795 | | 33,957 | | 30,648 | | 2,874 | | 2,153 | | 7,886 | | 22,274 | |
| Pension-related items | | 6,857 | | 80,127 | | 44,451 | | (2,110) | | (2,930) | | (23,489) | | 2,991 | |
| Nuclear decommissioning liabilities | | | | (63,189 | ) | | | 51,593 | | | | 92,930 | | | | - | | | | - | | | | - | | | | (65,564 | ) |
| Regulatory liabilities | | | | 79,805 | | | | 47,474 | | | | 173,046 | | | | 8,515 | | | | 47,257 | | | | 3,429 | | | | 45,327 | |
| Pension and other post- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| employment benefits | | | | (75,278 | ) | | | 47,469 | | | | 34,283 | | | | (22,140 | ) | | | (10,815 | ) | | | (40,389 | ) | | | (19,160 | ) |
| Sale and leaseback | | - | | - | | 84,517 | | - | | - | | - | | 176,417 | | | - | | | | - | | | | 57,423 | | | | - | | | | - | | | | - | | | | 137,651 | |
| Reserve for regulatory adjustments | | - | | 103,403 | | - | | - | | - | | - | | - | |
| Accumulated deferred investment tax credit | | | | 16,062 | | | | 36,642 | | | | 27,008 | | | | 2,776 | | | | 500 | | | | 6,210 | | | | 21,492 | |
| Provision for contingencies | | | | 4,723 | | | | 33,074 | | | | 48,241 | | | | 9,564 | | | | (2,865 | ) | | | (35,505 | ) | | | - | |
| Power purchase agreements | | | | 94 | | | | 37,771 | | | | - | | | | 84 | | | | 21 | | | | 2,752 | | | | - | |
| Unbilled/deferred revenues | | 13,619 | | (17,236) | | (1,464) | | 14,335 | | - | | 22,741 | | - | | | 27,651 | | | | (23,150 | ) | | | (7,101 | ) | | | 9,242 | | | | 3,352 | | | | 12,986 | | | | - | |
| Customer deposits | | 8,540 | | 616 | | 5,698 | | (1,890) | | 109 | | - | | - | |
| Rate refund | | 11,786 | | (6,041) | | 121 | | - | | - | | (4,018) | | - | |
| NOL carryforward | | - | | 9,398 | | 3,521 | | - | | 6,017 | | 156,153 | | 7,546 | |
| Compensation | | | | 3,587 | | | | 580 | | | | 18 | | | | (664 | ) | | | 13 | | | | 4,547 | | | | 180 | |
| Net operating loss carryforwards | | | | 102,034 | | | | - | | | | 460,367 | | | | 45,475 | | | | - | | | | 20,307 | | | | 86,228 | |
| Other | | 11,957 | | 6,780 | | 13,220 | | (5,701) | | 19,479 | | 40,032 | | 18,845 | | | 5,565 | | | | 6,106 | | | | 5,513 | | | | 8,758 | | | | 4,472 | | | | 6,707 | | | | 2,000 | |
| Total | | 71,554 | | 211,004 | | 180,712 | | 7,508 | | 24,828 | | 199,305 | | 228,073 | | | 101,054 | | | | 237,559 | | | | 891,728 | | | | 61,610 | | | | 41,935 | | | | (18,956 | ) | | | 208,154 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent accrued taxes (including | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| unrecognized tax benefits) | | (151,079) | | (167,324) | | (196,024) | | (33,505) | | (131,142) | | 35,424 | | (224,733) | | | 46,930 | | | | (239,670 | ) | | | 218,033 | | | | (1,121 | ) | | | 13,630 | | | | 55,113 | | | | (4,130 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| taxes and taxes accrued | | ($1,568,374) | | ($1,358,203) | | ($1,716,621) | | ($578,465) | | ($144,912) | | ($680,675) | | ($591,762) | | $ | (1,763,012 | ) | | $ | (1,425,444 | ) | | $ | (817,287 | ) | | $ | (718,003 | ) | | $ | (163,273 | ) | | $ | (974,093 | ) | | $ | (709,927 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | Entergy | | | | | | | | | | | | | | | Entergy | | | | | | | | | | | | | | | | |
| | | Entergy | | Gulf States | | Entergy | | Entergy | | Entergy | | Entergy | | System | | Entergy | | | Gulf States | | | Entergy | | | Entergy | | | Entergy | | | Entergy | | | System | |
| 2008 | | Arkansas | | Louisiana | | Louisiana | | Mississippi | | New Orleans | | Texas | | Energy | |
| 2011 | | | Arkansas | | | Louisiana | | | Louisiana | | | Mississippi | | | New Orleans | | | Texas | | | Energy | |
| | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant-related basis differences - net | | ($977,088) | | ($1,073,496) | | ($1,002,664) | | ($484,152) | | ($167,757) | | ($649,471) | | ($347,532) | |
| Net regulatory assets/(liabilities) | | (300,928) | | (356,750) | | (111,896) | | (15,597) | | 68,163 | | (93,918) | | (211,786) | |
| Power purchase agreements | | (68,778) | | 149,626 | | (557,859) | | (2,320) | | - | | 9,679 | | 26,872 | |
| Plant basis differences - net | | | $ | (1,334,016 | ) | | $ | (1,124,284 | ) | | $ | (1,077,835 | ) | | $ | (608,596 | ) | | $ | (148,296 | ) | | $ | (735,310 | ) | | $ | (505,369 | ) |
| Regulatory assets | | | | (222,429 | ) | | | (103,585 | ) | | | (249,459 | ) | | | (32,611 | ) | | | - | | | | (227,224 | ) | | | (120,886 | ) |
| Nuclear decommissioning trusts | | (117,260) | | (10,991) | | (3,031) | | - | | - | | - | | (37,128) | | | (53,789 | ) | | | (21,096 | ) | | | (22,441 | ) | | | - | | | | - | | | | - | | | | (19,138 | ) |
| Deferred fuel | | (46,880) | | (595) | | (2,416) | | (1,116) | | (8,255) | | (6,571) | | (10,232) | | | (82,452 | ) | | | (1,225 | ) | | | (4,285 | ) | | | 718 | | | | (331 | ) | | | 3,932 | | | | (8 | ) |
| Other | | (42,558) | | (3,720) | | (32,776) | | (22,337) | | (7,571) | | (21,104) | | 14,090 | | | (54,277 | ) | | | (1,394 | ) | | | (26,237 | ) | | | (7,263 | ) | | | (18,319 | ) | | | (14,098 | ) | | | (9,333 | ) |
| Total | | ($1,553,492) | | ($1,295,926) | | ($1,710,642) | | ($525,522) | | ($115,420) | | ($761,385) | | ($565,716) | | $ | (1,746,963 | ) | | $ | (1,251,584 | ) | | $ | (1,380,257 | ) | | $ | (647,752 | ) | | $ | (166,946 | ) | | $ | (972,700 | ) | | $ | (654,734 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Deferred tax assets: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred investment | | | | | | | | | | | | | | | |
| tax credits | | 20,353 | | 35,261 | | 31,878 | | 3,292 | | 951 | | 8,445 | | 23,603 | |
| Pension-related items | | 17,937 | | 60,338 | | 38,037 | | (1,988) | | (6,857) | | (19,530) | | 6,410 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear decommissioning liabilities | | | | (104,862 | ) | | | (38,683 | ) | | | 56,399 | | | | - | | | | - | | | | - | | | | (47,360 | ) |
| Regulatory liabilities | | | | 29,473 | | | | (39,265 | ) | | | 111,705 | | | | 1,497 | | | | 53,191 | | | | 35,072 | | | | 18,301 | |
| Pension and other post- | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| employment benefits | | | | (75,399 | ) | | | 123,085 | | | | 19,866 | | | | (30,390 | ) | | | (11,713 | ) | | | (41,964 | ) | | | (19,593 | ) |
| Sale and leaseback | | - | | - | | 89,543 | | - | | - | | - | | 162,936 | | | - | | | | - | | | | 66,801 | | | | - | | | | - | | | | - | | | | 150,629 | |
| Reserve for regulatory adjustments | | - | | 106,302 | | - | | - | | - | | - | | - | |
| Accumulated deferred | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| investment tax credit | | | | 16,843 | | | | 31,367 | | | | 28,197 | | | | 2,437 | | | | 592 | | | | 6,769 | | | | 22,133 | |
| Provision for contingencies | | | | 4,167 | | | | (1,406 | ) | | | 3,940 | | | | 2,465 | | | | 10,121 | | | | 2,299 | | | | - | |
| Power purchase agreements | | | | 94 | | | | 3,938 | | | | (1 | ) | | | 2,383 | | | | 22 | | | | 2,547 | | | | - | |
| Unbilled/deferred revenues | | 11,508 | | (8,916) | | (2,322) | | (3,986) | | - | | 18,951 | | - | | | 15,222 | | | | (21,918 | ) | | | (7,108 | ) | | | 8,990 | | | | 2,707 | | | | 14,324 | | | | - | |
| Customer deposits | | 9,408 | | 35,224 | | 16,804 | | 15,014 | | 109 | | - | | - | |
| Rate refund | | 814 | | (5,231) | | 9,971 | | - | | 2 | | (5,135) | | - | |
| NOL carryforward | | 32,286 | | - | | - | | - | | - | | 100,687 | | 1,393 | |
| Net operating loss carryforwards | | | | - | | | | - | | | | 39,153 | | | | - | | | | - | | | | 58,547 | | | | - | |
| Other | �� | 38,641 | | 29,861 | | 19,375 | | 7,003 | | (8,776) | | 9,021 | | (3,229) | | | 56,116 | | | | 27,548 | | | | 33,675 | | | | 6,206 | | | | 1,899 | | | | 8,753 | | | | 40,759 | |
| Total | | 130,947 | | 252,839 | | 203,286 | | 19,335 | | (14,571) | | 112,439 | | 191,113 | | | (58,346 | ) | | | 84,666 | | | | 352,627 | | | | (6,412 | ) | | | 56,819 | | | | 86,347 | | | | 164,869 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Noncurrent accrued taxes (including | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| unrecognized tax benefits) | | (83,953) | | (215,323) | | (366,480) | | (45,671) | | 9,777 | | (19,439) | | (176) | | | (27,718 | ) | | | (206,752 | ) | | | (75,750 | ) | | | (6,271 | ) | | | (27,859 | ) | | | 39,799 | | | | (165,981 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated deferred income | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| taxes and taxes accrued | | ($1,506,498) | | ($1,258,410) | | ($1,873,836) | | ($551,858) | | ($120,214) | | ($668,385) | | ($374,779) | | $ | (1,833,027 | ) | | $ | (1,373,670 | ) | | $ | (1,103,380 | ) | | $ | (660,435 | ) | | $ | (137,986 | ) | | $ | (846,554 | ) | | $ | (655,846 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Registrant Subsidiaries’ estimated tax attributeattributes carryovers and their expiration dates as of December 31, 2009,2012 are as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | |
| | | | | | | | | | | | | | | |
| Federal net operating losses | | $97 million | | - | | $189 million | | - | | $9 million | | $534 million | | - |
| Year(s) of expiration | | 2028 | | N/A | | 2028 | | N/A | | 2028 | | 2028 | | N/A |
| | | | | | | | | | | | | | | |
| State net operating losses | | - | | $210 million | | $127 million | | - | | $64 million | | - | | - |
| Year(s) of expiration | | N/A | | 2023 | | 2023 | | N/A | | 2021-2023 | | N/A | | N/A |
| | | | | | | | | | | | | | | |
| Federal minimum tax credits | | $5 million | | $17 million | | - | | $1 million | | $1 million | | - | | - |
| Year(s) of expiration | | never | | never | | N/A | | never | | never | | N/A | | N/A |
| | | | | | | | | | | | | | | |
| Other federal credits | | $1 million | | $1 million | | $1 million | | - | | $1 million | | - | | $1 million |
| Year(s) of expiration | | 2024-2028 | | 2024-2028 | | 2024-2028 | | N/A | | 2024-2028 | | N/A | | 2024-2028 |
| | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | |
Federal net operating losses | | $1.3 billion | | $321 million | | $2.3 billion | | $155 million | | $81 million | | $60 million | | $875 million |
| Year(s) of expiration | | 2029-2031 | | 2029-2030 | | 2028-2032 | | 2029-2032 | | 2030-2032 | | 2029-2032 | | 2029-2032 |
| | | | | | | | | | | | | | |
| State net operating losses | | $48 million | | $852 million | | $3.2 billion | | - | | $94 million | | - | | $220 million |
| Year(s) of expiration | | 2023-2026 | | 2024-2025 | | 2023-2027 | | N/A | | 2025-2027 | | N/A | | 2029-2030 |
| | | | | | | | | | | | | | |
| Misc. federal credits | | $2 million | | $1 million | | $4 million | | $1 million | | $1 million | | - | | $2 million |
| Year(s) of expiration | | 2024-2031 | | 2024-2031 | | 2026-2031 | | 2024-2031 | | 2024-2031 | | N/A | | 2024-2031 |
| | | | | | | | | | | | | | |
| State credits | | - | | - | | - | | $10.1 million | | - | | $4.2 million | | $15.6 million |
| Year(s) of expiration | | N/A | | N/A | | N/A | | 2013-2016 | | N/A | | 2013-2027 | | 2015-2016 |
As a result of the accounting for uncertain tax positions, the amount of the deferred tax assets reflected in the financial statements is less than the amount of the tax effect of the federal and state net operating loss carryovers and tax credit carryovers.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Unrecognized tax benefits
Accounting standards establish a "more-likely-than-not"“more-likely-than-not” recognition threshold that must be met before a tax benefit can be recognized in the financial statements. If a tax deduction is taken on a tax return, but does not meet the more-likely-than-not recognition threshold, an increase in income tax liability, above what is payable on the tax return, is required to be recorded. A reconciliation of Entergy'sEntergy’s beginning and ending amount of unrecognized tax benefits is as follows:
| | | 2009 | | 2008 | | 2007 | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Gross balance at January 1 | | $1,825,447 | | $2,523,794 | | $2,265,257 | | $ | 4,387,780 | | | $ | 4,949,788 | | | $ | 4,050,491 | |
| Additions based on tax positions related to the current year | | | | | | | | | 163,612 | | | | 211,966 | | | | 480,843 | |
| Additions for tax positions of prior years | | 697,615 | | 259,434 | | 670,385 | | | 1,517,797 | | | | 332,744 | | | | 871,682 | |
| Reductions for tax positions of prior years | | (372,862) | | (166,651) | | (450,252) | | | (476,873 | ) | | | (259,895 | ) | | | (438,460 | ) |
| Settlements | | (385,321) | | (1,169,319) | | (102,485) | | | (1,421,913 | ) | | | (841,528 | ) | | | (10,462 | ) |
| Lapse of statute of limitations | | (1,147) | | - | | (1,938) | | | - | | | | (5,295 | ) | | | (4,306 | ) |
| Gross balance at December 31 | | 4,050,491 | | 1,825,447 | | 2,523,794 | | | 4,170,403 | | | | 4,387,780 | | | | 4,949,788 | |
| Offsets to gross unrecognized tax benefits: | | | | | | | | | | | | | | | | | | |
| Credit and loss carryovers | | (3,349,589) | | (1,265,734) | | (654,888) | | | (4,022,535 | ) | | | (3,212,397 | ) | | | (3,771,301 | ) |
| Cash paid to taxing authorities | | (373,000) | | (548,000) | | (402,000) | | | - | | | | (363,266 | ) | | | (373,000 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments (1) | | | | | | | | $ | 147,868 | | | $ | 812,117 | | | $ | 805,487 | |
(1) Potential tax liability above what is payable on tax returns| (1) | Potential tax liability above what is payable on tax returns |
The balances of unrecognized tax benefits include $522$203 million, $543$521 million, and $242$605 million as of December 31, 2009, 2008,2012, 2011, and 2007,2010, respectively, which, if recognized, would lower the effective income tax rates. Because of the effect of deferred tax accounting, the remaining balances of unrecognized tax benefits of $3.53$3.968 billion, $1.28$3.867 billion, and $1.88$4.345 billion as of December 31, 2009, 20082012, 2011, and 20072010, respectively, if disallowed, would not affect the annual effective income tax rate but would accelerate the payment of cash to the taxing authority to an earlier period.
Entergy has made deposits with the IRS against its potential liabilities arising from audit adjustments and settlements related to its uncertain tax positions. Deposits are expected to be made to the IRS as the cash tax benefits of uncertain tax positions are realized. The total amount of cash deposits shown for 2011 has been fully offset against settled liabilities which arose in 2012.
Entergy accrues interest and penalties expensesexpense, if any, related to unrecognized tax benefits in income tax expense. Entergy'sEntergy’s December 31, 2009, 2008,2012, 2011, and 20072010 accrued balance of unrecognized tax benefits includes approximately $48 million, $55 million, and $50 million, respectively, accrued for the possible payment of interest is approximately $146.3 million, $99 million, and penalties.
Entergy has deposits of $373$45 million, on account with the IRS to cover its uncertain tax positions.respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
A reconciliation of the Registrant Subsidiaries'Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2009, 2008,2012, 2011, and 20072010 is as follows:
| 2012 | | Entergy
Arkansas | | | Entergy Gulf States Louisiana | | | Entergy
Louisiana | | | Entergy
Mississippi | | | Entergy
New Orleans | | | Entergy
Texas | | | System
Energy | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | |
| Gross balance at January 1, 2012 | | $ | 335,493 | | | $ | 390,493 | | | $ | 446,187 | | | $ | 11,052 | | | $ | 56,052 | | | $ | 19,225 | | | $ | 281,183 | |
| Additions based on tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions related to the | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| current year | | | 10,409 | | | | 8,974 | | | | 67,721 | | | | 8,401 | | | | 497 | | | | 1,656 | | | | 8,715 | |
| Additions for tax positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| of prior years | | | 429,232 | | | | 392,548 | | | | 331,432 | | | | 4,057 | | | | 445 | | | | 4,834 | | | | 271,172 | |
| Reductions for tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions of prior years | | | (39,534 | ) | | | (50,518 | ) | | | (169,465 | ) | | | (5,703 | ) | | | (2,506 | ) | | | (11,649 | ) | | | (20,934 | ) |
| Settlements | | | (390,931 | ) | | | (275,776 | ) | | | (139,202 | ) | | | (966 | ) | | | (2,470 | ) | | | (112 | ) | | | (279,790 | ) |
| Gross balance at December 31, 2012 | | | 344,669 | | | | 465,721 | | | | 536,673 | | | | 16,841 | | | | 52,018 | | | | 13,954 | | | | 260,346 | |
| Offsets to gross unrecognized | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Loss carryovers | | | (342,127 | ) | | | (160,955 | ) | | | (536,673 | ) | | | (16,841 | ) | | | (35,511 | ) | | | (1,593 | ) | | | (249,424 | ) |
| Cash paid to taxing authorities | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | |
| Unrecognized tax benefits net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| unused tax attributes and payments | | $ | 2,542 | | | $ | 304,766 | | | $ | - | | | $ | - | | | $ | 16,507 | | | $ | 12,361 | | | $ | 10,922 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2011 | | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | (In Thousands) | |
| | | (In Thousands) | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Gross balance at January 1, 2009 | | $240,203 | | $275,378 | | $298,650 | | $31,724 | | $26,050 | | $39,202 | | $172,168 | |
| Gross balance at January 1, 2011 | | | $ | 240,239 | | | $ | 353,886 | | | $ | 505,188 | | | $ | 24,163 | | | $ | 18,176 | | | $ | 14,229 | | | $ | 224,518 | |
| Additions based on tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions related to the | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| current year | | 9,826 | | 5,436 | | 10,197 | | 283 | | 17 | | 97 | | 6,812 | | | 11,216 | | | | 9,398 | | | | 8,748 | | | | 457 | | | | 50,212 | | | | 1,760 | | | | 44,419 | |
| Additions for tax positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| of prior years | | 80,968 | | 102,466 | | 108,399 | | 1,256 | | 109 | | 28,821 | | 30,586 | | | 44,202 | | | | 50,944 | | | | 21,052 | | | | 21,902 | | | | 7,343 | | | | 7,533 | | | | 14,200 | |
| Reductions for tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions of prior years | | (22,830) | | (33,000) | | (45,613) | | (4,235) | | (70,391) | | (17,853) | | (244) | | | (3,255 | ) | | | (21,719 | ) | | | (27,991 | ) | | | (5,022 | ) | | | (12,289 | ) | | | (3,432 | ) | | | (4,942 | ) |
| Settlements | | (14,247) | | (38,969) | | (19,056) | | (11,891) | | (9,080) | | (17,968) | | 1,925 | | | 43,091 | | | | (2,016 | ) | | | (60,810 | ) | | | (30,448 | ) | | | (7,390 | ) | | | (865 | ) | | | 2,988 | |
| Gross balance at December 31, 2009 | | 293,920 | | 311,311 | | 352,577 | | 17,137 | | (53,295) | | 32,299 | | 211,247 | |
| Gross balance at December 31, 2011 | | | | 335,493 | | | | 390,493 | | | | 446,187 | | | | 11,052 | | | | 56,052 | | | | 19,225 | | | | 281,183 | |
| Offsets to gross unrecognized | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Loss carryovers | | (39,847) | | (20,031) | | (70,428) | | (1,618) | | (633) | | (30,921) | | (1,297) | | | (146,429 | ) | | | (26,394 | ) | | | (216,720 | ) | | | (5,930 | ) | | | (1,211 | ) | | | (10,645 | ) | | | (10,752 | ) |
| Cash paid to taxing authorities | | (75,977) | | (45,493) | | - | | (7,556) | | (1,174) | | (1,376) | | (41,878) | | | (75,977 | ) | | | (45,493 | ) | | | - | | | | (7,556 | ) | | | (1,174 | ) | | | (1,376 | ) | | | (41,878 | ) |
| Unrecognized tax benefits net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| unused tax attributes and payments | unused tax attributes and payments | $178,096 | | $245,787 | | $282,149 | | $7,963 | | ($55,102) | | $2 | | $168,072 | | $ | 113,087 | | | $ | 318,606 | | | $ | 229,467 | | | $ | (2,434 | ) | | $ | 53,667 | | | $ | 7,204 | | | $ | 228,553 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| Gross balance at January 1, 2008 | | $309,019 | | $224,379 | | $66,291 | | $69,734 | | $46,904 | | $86,732 | | $197,307 |
| Additions based on tax | | | | | | | | | | | | | | |
| positions related to the | | | | | | | | | | | | | | |
| current year | | 685 | | 89,966 | | 236,499 | | 773 | | 404 | | 338 | | 502 |
| Additions for tax positions | | | | | | | | | | | | | | |
| of prior years | | 12,465 | | 10,784 | | 5,300 | | 7,494 | | 1,025 | | 189 | | 1,405 |
| Reductions for tax | | | | | | | | | | | | | | |
| positions of prior years | | (330) | | (372) | | (1,567) | | (8,051) | | (13,645) | | (5,082) | | (192) |
| Settlements | | (81,636) | | (49,379) | | (7,873) | | (38,226) | | (8,638) | | (42,975) | | (26,854) |
| Gross balance at December 31, 2008 | | 240,203 | | 275,378 | | 298,650 | | 31,724 | | 26,050 | | 39,202 | | 172,168 |
| Offsets to gross unrecognized | | | | | | | | | | | | | | |
| tax benefits: | | | | | | | | | | | | | | |
| Loss carryovers | | (147,737) | | - | | (127,572) | | - | | (6,392) | | (39,202) | | - |
| Cash paid to taxing authorities | | (69,273) | | (36,812) | | - | | (806) | | (554) | | (1,376) | | (66,398) |
| Unrecognized tax benefits net of | | | | | | | | | | | | | | |
| unused tax attributes and payments | | $23,193 | | $238,566 | | $171,078 | | $30,918 | | $19,104 | | ($1,376) | | $105,770 |
| | | | | | | | | | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2010 | | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | (In Thousands) | |
| | | (In Thousands) | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
| Gross balance at January 1, 2007 | | $199,090 | | $176,649 | | $72,620 | | $50,374 | | $22,027 | | $49,344 | | $194,881 | |
| Gross balance at January 1, 2010 | | | $ | 293,920 | | | $ | 311,311 | | | $ | 352,577 | | | $ | 17,137 | | | $ | (53,295 | ) | | $ | 32,299 | | | $ | 211,247 | |
| Additions based on tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions related to the | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| current year | | 152 | | 217 | | 673 | | 19,106 | | 25,874 | | 596 | | 1,184 | | | 38,205 | | | | 87,755 | | | | 183,188 | | | | 4,679 | | | | 173 | | | | 5,169 | | | | 16,829 | |
| Additions for tax positions | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| of prior years | | 115,440 | | 78,724 | | 20,798 | | 4,133 | | 1,180 | | 48,249 | | 48,290 | | | 1,838 | | | | 25,960 | | | | 34,236 | | | | 6,857 | | | | 72,169 | | | | 5,868 | | | | 10,402 | |
| Reductions for tax | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| positions of prior years | | (10,537) | | (15,755) | | (28,031) | | (13,509) | | (2,361) | | (1,362) | | (1,230) | | | (92,699 | ) | | | (71,033 | ) | | | (64,868 | ) | | | (4,469 | ) | | | (863 | ) | | | (29,100 | ) | | | (13,116 | ) |
| Settlements | | 4,874 | | (15,456) | | 231 | | 9,630 | | 184 | | (10,095) | | (45,818) | | | (1,025 | ) | | | (107 | ) | | | 55 | | | | (41 | ) | | | (8 | ) | | | (7 | ) | | | (844 | ) |
| Gross balance at December 31, 2007 | | 309,019 | | 224,379 | | 66,291 | | 69,734 | | 46,904 | | 86,732 | | 197,307 | |
| Gross balance at December 31, 2010 | | | | 240,239 | | | | 353,886 | | | | 505,188 | | | | 24,163 | | | | 18,176 | | | | 14,229 | | | | 224,518 | |
| Offsets to gross unrecognized | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| tax benefits: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Loss carryovers | | (100,545) | | (65,945) | | (66,291) | | - | | (46,904) | | - | | (31) | | | (123,968 | ) | | | (29,257 | ) | | | (131,805 | ) | | | (6,477 | ) | | | (3,751 | ) | | | (6,269 | ) | | | (10,487 | ) |
| Cash paid to taxing authorities | | (45,000) | | (25,000) | | - | | - | | - | | - | | (50,000) | | | (75,977 | ) | | | (45,493 | ) | | | - | | | | (7,556 | ) | | | (1,174 | ) | | | (1,376 | ) | | | (41,878 | ) |
| Unrecognized tax benefits net of | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| unused tax attributes and payments | | $163,474 | | $133,434 | | $- | | $69,734 | | $- | | $86,732 | | $147,276 | | $ | 40,294 | | | $ | 279,136 | | | $ | 373,383 | | | $ | 10,130 | | | $ | 13,251 | | | $ | 6,584 | | | $ | 172,153 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
The Registrant Subsidiaries'Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would affect the effectivehave reduced income tax rateexpense as follows:
| | December 31, 2009 | | December 31, 2008 | | December 31, 2007 | | | December 31, 2012 | | | December 31, 2011 | | | December 31, 2010 | |
| | (In Millions) | | (In Millions) | |
| | | | | | | | | | | | | | | | |
| Entergy Arkansas | $1.2 | | $1.2 | | ($1.6) | | | $ | 0.6 | | | $ | - | | | $ | 0.2 | |
| Entergy Gulf States Louisiana | $69.8 | | $75.2 | | $1.3 | | | $ | 44.0 | | | $ | 107.9 | | | $ | 129.6 | |
| Entergy Louisiana | $192.7 | | $210.4 | | $0.7 | | | $ | 92.4 | | | $ | 281.3 | | | $ | 286.7 | |
| Entergy Mississippi | $3.3 | | $2.5 | | $1.8 | | | $ | 3.9 | | | $ | 3.8 | | | $ | 5.3 | |
| Entergy New Orleans | $0.3 | | $0.7 | | $0.5 | | | $ | - | | | $ | - | | | $ | - | |
| Entergy Texas | $1.2 | | $0.6 | | $1.8 | | | $ | 8.6 | | | $ | 7.3 | | | $ | 6.0 | |
| System Energy | $8.7 | | $3.9 | | $3.0 | | | $ | 3.5 | | | $ | - | | | $ | 12.1 | |
The Registrant Subsidiaries accrue interest and penalties related to unrecognized tax benefits in income tax expense. Included in thePenalties have not been accrued. Accrued balances of unrecognized tax benefits were accruals for the possible payment of interest and penaltyare as follows:
| | December 31, 2009 | | December 31, 2008 | | December 31, 2007 | | December 31, 2012 | | | December 31, 2011 | | | December 31, 2010 | |
| | (In Millions) | | (In Millions) | |
| | | | | | | | | | | | | | | |
| Entergy Arkansas | $0.7 | | $1.6 | | $1.4 | | $ | 21.8 | | | $ | 11.4 | | | $ | - | |
| Entergy Gulf States Louisiana | $2.3 | | $1.4 | | $0.9 | | $ | 33.1 | | | $ | 14.4 | | | $ | 9.7 | |
| Entergy Louisiana | $1.2 | | $- | | $- | | $ | 0.9 | | | $ | 0.8 | | | $ | 3.3 | |
| Entergy Mississippi | $2.1 | | $2.1 | | $1.7 | | $ | 2.4 | | | $ | 1.7 | | | $ | 1.6 | |
| Entergy New Orleans | $0.3 | | $0.7 | | $0.5 | | $ | 0.1 | | | $ | 2.4 | | | $ | - | |
| Entergy Texas | $0.2 | | $0.2 | | $1.4 | | $ | 0.7 | | | $ | 0.1 | | | $ | 0.1 | |
| System Energy | $7.2 | | $3.3 | | $2.7 | | $ | 33.2 | | | $ | 18.5 | | | $ | 8.2 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy and the Registrant Subsidiaries do not expect that total unrecognized tax benefits will significantly change within the next twelve months; however, the results of pending litigations and audit issues, discussed below, could result in significant changes.
Income Tax Litigation
ForIn October 2010 the U.S. Tax Court entered a decision in favor of Entergy for tax years 1997 and 1998, a U.S. Tax Court trial was held in April 2008.1998. The issues beforedecided by the Tax Court are as follows:
| · | The ability to credit the U.K. Windfall Tax against U.S. tax as a foreign tax credit. The U.K. Windfall Tax relates to Entergy'sEntergy’s former investment in London Electricity. |
| · | The validity of Entergy'sEntergy’s change in method of tax accounting for street lighting assets and the related increase in depreciation deductions. |
The IRS did not appeal street lighting depreciation, and that matter is final. The IRS filed an appeal of the U.K. Windfall Tax decision, however, with the U.S. Court of Appeals for the Fifth Circuit in December 2010. Oral arguments were heard in November 2011. In June 2012 the U.S. Court of Appeals for the Fifth Circuit unanimously affirmed the U.S. Tax Court decision. As a result of this decision, Entergy reversed its liability for uncertain tax positions associated with this issue. On November 20, 2009, Entergy was directed bySeptember 4, 2012, the U.S. Solicitor General, on behalf of the Commissioner of Internal Revenue, petitioned the U.S. Supreme Court for a writ of certiorari to review the Fifth Circuit judgment.
Concurrent with the Tax Court’s issuance of a favorable decision regarding the above issues, the Tax Court issued a favorable decision in a separate proceeding, PPL Corp. v. Commissioner, regarding the creditability of the U.K. Windfall Tax. The IRS appealed the PPL decision to submitthe United States Court of Appeals for the Third Circuit. In December 2011 the Third Circuit reversed the Tax Court’s holding in PPL Corp. v. Commissioner, stating that the U.K. tax was not eligible for the foreign tax credit. PPL Corp. petitioned the U.S. Supreme Court for a supplementwrit of certiorari to previously filed supplemental briefs addressingreview the issuesU.S. Court of Appeals for the Third Circuit decision. On October 29, 2012, the U.S. Supreme Court granted PPL Corp.’s petition for certiorari. The Solicitor General’s petition for writ of certiorari in dispute. AEntergy’s case is currently on hold pending the disposition of the PPL case. Entergy’s case will be determined consistent with the U.S. Supreme Court’s decision is anticipated byin the first or second quarter 2010.PPL proceeding. Oral argument in PPL’s case was heard on February 20, 2013.
OnThe total tax at issue on the U.K. Windfall Tax credit matter is $152 million, and interest on the underpayment of such tax is estimated to be $102 million resulting in total exposure of $254 million.
In February 21, 2008 the IRS issued a Statutory Notice of Deficiency for the year 2000. A Tax Court Petition was filed on May 5, 2008. Trial is set for April 17, 2010. The Petition challenges the IRS assessment on thedeficiency resulted from a disallowance of foreign tax credits (the same two issues described aboveissue discussed above) as well as the following issue:
· | The allowance of depreciation deductions that resulted from Entergy's purchase price allocations on its acquisitions of its Non-Utility Nuclear plants. |
With respect to the U.K. Windfalldisallowance of depreciation deductions on non-utility nuclear plants. Entergy filed a Tax issue, the total tax includedCourt petition in IRS Notices of Deficiency is $82 million. The total tax and interest associated with this issue for all years is $209 million before consideration of cash deposits made withMay 2008 challenging the IRS to offsettreatment of these issues. In June 2010 a trial on the potential exposure.
With respect todepreciation issue was held in Washington, D.C. In February 2011 a joint stipulation of settled issues was filed under which the street lighting issue, the total tax included in IRS Notices of Deficiency is $22 million. The federal and state tax and interest associatedconceded its position with this issue total $61 million for all open tax years.
With respect to the depreciation deducted on Non-Utility Nuclear plant acquisitions,issue. The outcome of the totalforeign tax includedcredit matter for the year 2000 will also be determined consistent with the U.S. Supreme Court’s decision in IRS Notices of Deficiency is $7 million. The federal and state tax and interest associated with this issue total $270 million for all open tax years.the PPL proceeding.
Income Tax Audits
Entergy or one ofand its subsidiaries filesfile U.S. federal and various state and foreign income tax returns. Other than the matters discussed in the Income Tax Litigation section above, the IRS'sIRS’s and substantially all state taxing authorities'authorities’ examinations are completed for years before 2004.2005.
2002-2003 IRS Audit
In September 2009, Entergy entered into a partial agreement with the IRS for the years 2002 and 2003. It is aIn the partial agreement, because Entergy did not agree to the IRS's adjustmentsIRS’s disallowance of foreign tax credits for the U.K. Windfall Tax foreign tax credit and the street lighting depreciation issues. Entergy expects to receive a Notice of Deficiency fromAs discussed above, the IRS did not appeal the Tax Court ruling on these two issues in the first quarter 2010. These issuesstreet lighting depreciation. The U.K. Windfall tax credit issue will be governed by the outcome of a previous U.S. Supreme Court's decision in the PPL Corp. proceeding as explained in “Income Tax Court trial for the tax years 1997 and 1998 for which Entergy is awaiting a decision.Litigation”, above.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2004-2005 IRS Audit
The IRS issued its 2004-2005 Revenue Agent'sAgent’s Report on(RAR) in May 26, 2009.
OnIn June 25, 2009, Entergy filed a formal Protestprotest with the IRS Appeals OfficeDivision indicating disagreement with certain issues contained in the Revenue Agent’s Report.2004-2005 RAR. The major issues in dispute are:
| · | Depreciation of street lighting assets (issue before(because the IRS did not appeal the Tax Court) |
· | Depreciable basis of assets acquiredCourt’s 2010 decision on this issue, it will be fully allowed in Non-Utility Nuclear plant purchases (issue before the Tax Court) |
· | Qualified research expendituresfinal Appeals Division calculations for purposes of the research creditthis audit). |
| · | Inclusion of nuclear decommissioning liabilities in cost of goods sold for the nuclear power plants owned by the Utility resulting from an Application for Change in Accounting Method for tax purposes (the “2004 CAM”). |
ItDuring the fourth quarter 2012, Entergy settled the position relating to the 2004 CAM. Under the settlement Entergy conceded its tax position, resulting in an increase in taxable income of approximately $2.97 billion for the tax years 2004 - 2007. The settlement provides that Entergy Louisiana is anticipated that IRS Appeals proceedings on these disputed issues will commence inentitled to additional tax depreciation of approximately $547 million for years 2006 and beyond. The deferred tax asset net of interest charges associated with the second quarter of 2010.settlement is $155 million for Entergy. There was a related increase to Entergy Louisiana’s member’s equity account.
2006-2007 IRS Audit
The IRS commenced an examination of Entergy's 2006issued its 2006-2007 RAR in October 2011. In connection with the 2006-2007 IRS audit and 2007 U.S. federal income tax returns inresulting RAR, Entergy resolved the third quarter 2009. To date, the IRS has not proposed any adjustments in the audit of these returns.significant issues discussed below.
Other Tax Matters
WhenIn August 2011, Entergy Louisiana, Inc. restructured effective December 31, 2005, Entergy Louisiana agreed, under the terms of the merger plan, to indemnify its parent, Entergy Louisiana Holdings, Inc. (formerly, Entergy Louisiana, Inc.) for certain tax obligations that arose from the 2002-2003 IRS partial agreement. Because theentered into a settlement agreement with the IRS was settledrelating to the mark-to-market income tax treatment of various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility. See Note 8 to the financial statements for further details regarding this contract and a previous LPSC-approved settlement regarding the tax treatment of the contract.
With respect to income tax accounting for wholesale electric power purchase agreements, Entergy recognized income for tax purposes of approximately $1.5 billion, which represents a reversal of previously deducted temporary differences on which deferred taxes had been provided. Also in connection with this settlement, Entergy recognized a gain for income tax purposes of approximately $1.03 billion on the formation of a wholly-owned subsidiary in 2005 with a corresponding step-up in the fourth quarter 2009,tax basis of depreciable assets resulting in additional tax depreciation at Entergy Louisiana. Because Entergy Louisiana paidis entitled to deduct additional tax depreciation of $1.03 billion in the future, Entergy Louisiana Holdings approximately $289 million pursuantrecorded a deferred tax asset for this additional tax basis. The tax expense associated with the gain is offset by recording the deferred tax asset and by utilization of net operating losses. With the recording of the deferred tax asset, there was a corresponding increase to these intercompany obligationsEntergy Louisiana’s member’s equity account. The agreement with the IRS effectively settled the tax treatment of various wholesale electric power purchase and sale agreements, resulting in the fourthreversal in third quarter 2009.2011 of approximately $422 million of deferred tax liabilities and liabilities for uncertain tax positions at Entergy Louisiana, with a corresponding reduction in income tax expense. Under the terms of an LPSC-approved final settlement, Entergy Louisiana recorded a $199 million regulatory charge and a corresponding net-of-tax regulatory liability.
After consideration of the taxable income recognition and the additional depreciation deductions provided for in the settlement, Entergy’s net operating loss carryover was reduced by approximately $2.5 billion.
Entergy Corporation and subsidiaries amendedSubsidiaries
Notes to Financial Statements
2008-2009 IRS Audit
In the third quarter 2008, Entergy Louisiana and Entergy Gulf States Louisiana received $679 million and $274.7 million, respectively, from the Louisiana Utilities Restoration Corporation (“LURC”). These receipts from LURC were from the proceeds of a Louisiana Act 55 financing of the costs incurred to restore service following Hurricane Katrina and Subsidiary Companies Intercompany Income Tax Allocation Agreement such that Entergy Corporation shall be treated, under all provisions of such Agreement, in a manner that is identicalHurricane Rita. See Note 2 to the financial statements for further details regarding the financings.
In June 2012, Entergy effectively settled the tax treatment afforded all subsidiaries, direct or indirect, of the receipt of these funds, which resulted in an increase to 2008 taxable income of $129 million and $104 million for Entergy Corporation.Louisiana and Entergy Gulf States Louisiana, respectively. As a result of the settlement, Entergy recorded an income tax benefit of $172 million, including $143 million for Entergy Louisiana and $20 million for Entergy Gulf States Louisiana, resulting from the reversal of liabilities for uncertain tax positions. Under the terms of an LPSC-approved settlement related to the Louisiana Act 55 financings, Entergy Louisiana and Entergy Gulf States Louisiana recorded, respectively, a $137 million ($84 million net-of-tax) and a $28 million ($17 million net-of-tax) regulatory charge and a corresponding regulatory liability to reflect their obligations to customers with respect to the settlement. See Note 8 to the financial statements for further discussion of the LPSC settlement.
In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method of Accounting(the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code. In the Application,Applications, Entergy is requesting permissionproposed to treat the nuclear decommissioning liability associated with the operation of its nuclear power plants as a production cost properly includable in cost of goods sold. The effect of this change for Entergy isthe 2009 CAM was a $5.7 billion reduction in 2009 taxable income. The 2009 CAM was adjusted to $9.3 billion in 2012.
In the fourth quarter 2012 the IRS disallowed the reduction to 2009 taxable income within Non-Utility Nuclear.related to the 2009 CAM. Entergy has disagreed with this disallowance and will file a protest with IRS Appeals at the conclusion of the 2008-09 examination.
Other Tax Matters
Entergy regularly negotiates with the IRS to achieve settlements. The results of all pending litigations and audit issues could result in significant changes to the amounts of unrecognized tax benefits, as discussed above.
In March 2010, Entergy filed an Application for Change in Accounting Method with the IRS. In the application, Entergy proposed to change the definition of unit of property for its generation assets to determine the appropriate characterization of costs associated with such units as capital or repair under the Internal Revenue Code and related Treasury Regulations. The effect of this change was an approximate $1.3 billion reduction in 2010 taxable income for Entergy, including reductions of $292 million for Entergy Arkansas, $132 million for Entergy Gulf States Louisiana, $185 million for Entergy Louisiana, $48 million for Entergy Mississippi, $45 million for Entergy Texas, $13 million for Entergy New Orleans, and $180 million for System Energy.
During the second quarter 2011, Entergy filed an Application for Change in Accounting Method with the IRS related to the allocation of overhead costs between production and non-production activities. The accounting method affects the amount of overhead that will be capitalized or deducted for tax purposes. The accounting method is expected to be implemented for the 2014 tax year.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 4. REVOLVING CREDIT FACILITIES, LINES OF CREDIT, AND SHORT-TERM BORROWINGS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy Corporation has in place a revolving credit facility that expires in August 2012 and has a borrowing capacity of $3.5 billion.billion and expires in March 2017. Entergy Corporation also has the ability to issue letters of credit against 50% of the total borrowing capacity of the credit facility. The facilitycommitment fee is currently 0.09%0.275% of the commitment amount. FacilityCommitment fees and interest rates on loans under the credit facility can fluctuate depending on the senior unsecured debt ratings of Entergy Corporation. The weighted average interest rate for the year ended December 31, 20092012 was 1.377%2.04% on the drawn portion of the facility. Following is a summary of the borrowings outstanding and capacity available under the facility as of December 31, 2009.2012.
Capacity | | Borrowings | | Letters of Credit | | Capacity Available | | Borrowings | | Letters of Credit | | Capacity Available |
(In Millions) | | | | | | | | | | | | | | |
| $3,500 | | $2,566 | | $28 | | $906 | | $795 | | $8 | | $2,697 |
Entergy Corporation'sCorporation’s facility requires it to maintain a consolidated debt ratio of 65% or less of its total capitalization. Entergy is in compliance with this covenant. If Entergy fails to meet this ratio, or if Entergy Corporation or one of the Utility operating companies (except Entergy New Orleans) defaults on other indebtedness or is in bankruptcy or insolvency proceedings, an acceleration of the facility maturity date may occur.
In September 2012, Entergy Corporation implemented a commercial paper program with a program limit of up to $500 million. In November 2012, Entergy Corporation increased the limit for the commercial paper program to $1 billion. At December 31, 2012, Entergy Corporation had $665 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 2012 was 0.88%.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 20092012 as follows:
Company | | Expiration Expiration Date
| | Amount of Facility | | Interest Rate (a) | | Amount Drawn as of December 31, 20092012 |
| | | | | | | | | |
| Entergy Arkansas | | April 20102013 | | $8820 million (b) | | 5.00%1.81% | | - |
| Entergy Arkansas | | March 2017 | | $150 million (c) | | 1.71% | | - |
| Entergy Gulf States Louisiana | | August 2012March 2017 | | $100150 million (c)(d) | | 0.71%1.71% | | - |
| Entergy Louisiana | | August 2012March 2017 | | $200 million (d)(e) | | 0.64%1.71% | | - |
| Entergy Mississippi | | May 20102013 | | $35 million (e)(f) | | 1.98%1.96% | | - |
| Entergy Mississippi | | May 20102013 | | $25 million (e)(f) | | 1.98%1.96% | | - |
| Entergy Mississippi | | May 20102013 | | $10 million (e)(f) | | 1.91%1.96% | | - |
| Entergy New Orleans | | November 2013 | | $25 million (g) | | 1.69% | | - |
| Entergy Texas | | August 2012March 2017 | | $100150 million (f)(h) | | 0.71%1.96% | | - |
| (a) | The interest rate is the weighted average interest rate as of December 31, 2009 applied or2012 that would be applied to the outstanding borrowings under the facility. |
| (b) | The credit facility requires Entergy Arkansas to maintain a debt ratio of 65% or less of its total capitalization and contains an interest rate floor of 5%.capitalization. Borrowings under thethis Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable. |
| (c) | The credit facility allows Entergy Gulf States LouisianaArkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2009,2012, no letters of credit were outstanding. The credit facility requires Entergy Arkansas to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| (d) | The credit facility allows Entergy Gulf States Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2012, no letters of credit were outstanding. The credit facility requires Entergy Gulf States Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement, the amount of debt assumed by Entergy Texas ($168 million as of December 31, 2009 and $770 million as of December 31, 2008) is excluded from debt and capitalization in calculating the debt ratio. |
(d)(e) | The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2009,2012, no letters of credit were outstanding. The credit facility requires Entergy Louisiana to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
(e)(f) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable. Entergy Mississippi is required to maintain a consolidated debt ratio of 65% or less of its total capitalization. |
(f)(g) | The credit facility requires Entergy New Orleans to maintain a debt ratio of 65% or less of its total capitalization. |
| (h) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2009,2012, no letters of credit were outstanding. The credit facility requires Entergy Texas to maintain a consolidated debt ratio of 65% or less of its total capitalization. Pursuant to the terms of the credit agreement securitization bonds are excluded from debt and capitalization in calculating the debt ratio. |
The facility fees on the credit facilities range from 0.09%0.125% to 0.15%0.275% of the commitment amount.
The short-term borrowings of the Registrant Subsidiaries are limited to amounts authorized by the FERC. The current FERC-authorized limits are effective through October 31, 2011 under a FERC order dated October 14, 2009.2013. In addition to borrowings from commercial banks, these companies are authorized under a FERC order to borrow from the Entergy System money pool. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries'subsidiaries’ dependence on external short-term borrowings. Borrowings from the money pool and external borrowings combined may not exceed the FERC-authorized limits. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 20092012 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:
| | Authorized | | Borrowings |
| | (In Millions) |
| | | | |
| Entergy Arkansas | $250 | | - |
| Entergy Gulf States Louisiana | $200 | | $7 |
| Entergy Louisiana | $250 | | - |
| Entergy Mississippi | $175 | | - |
| Entergy New Orleans | $100 | | - |
| Entergy Texas | $200 | | - |
| System Energy | $200 | | - |
Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)
See Note 18 to the financial statements for a discussion of the consolidation of the nuclear fuel company variable interest entities (VIE). The nuclear fuel company variable interest entities have credit facilities and also issue commercial paper to finance the acquisition and ownership of nuclear fuel as follows as of December 31, 2012:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Company | | Expiration Date | | Amount of Facility | | Weighted Average Interest Rate on Borrowings (a) | | Amount Outstanding as of December 31, 2012 | |
| | | (Dollars in Millions) | |
| | | | | | | | | | |
| Entergy Arkansas VIE | | July 2013 | | $85 | | 2.31% | | $36.7 | |
| Entergy Gulf States Louisiana VIE | | July 2013 | | $85 | | n/a | | $- | |
| Entergy Louisiana VIE | | July 2013 | | $90 | | 2.36% | | $54.7 | |
| System Energy VIE | | July 2013 | | $100 | | 2.37% | | $40.0 | |
| (a) | AuthorizedIncludes letter of credit fees and bank fronting fees on commercial paper issuances by the nuclear fuel company variable interest entities for Entergy Arkansas, Entergy Louisiana, and System Energy. The nuclear fuel company variable interest entity for Entergy Gulf States Louisiana does not issue commercial paper, but borrows directly on its bank credit facility. |
Amounts outstanding on the Entergy Gulf States Louisiana nuclear fuel company variable interest entity’s credit facility are included in long-term debt on its balance sheet and commercial paper outstanding for the other nuclear fuel company variable interest entities is classified as a current liability on the respective balance sheets. The commitment fees on the credit facilities are 0.20% of the undrawn commitment amount. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio of 70% or less of its total capitalization.
The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 2012 as follows:
| Company | | BorrowingsDescription | | Amount |
| | (In Millions) | | | |
| Entergy Arkansas | $250 VIE | | -9% Series H due June 2013 | | $30 million |
| Entergy Arkansas VIE | | 5.69% Series I due July 2014 | | $70 million |
| Entergy Arkansas VIE | | 3.23% Series J due July 2016 | | $55 million |
| Entergy Arkansas VIE | | 2.62% Series K due December 2017 | | $60 million |
| Entergy Gulf States Louisiana | $200 VIE | | -5.56% Series N due May 2013 | | $75 million |
| Entergy Gulf States Louisiana VIE | | 3.25% Series Q due July 2017 | | $75 million |
| Entergy Louisiana | $250 VIE | | -5.69% Series E due July 2014 | | $50 million |
Entergy Mississippi | $175Louisiana VIE | | -3.30% Series F due March 2016 | | $20 million |
Entergy New Orleans | $100Louisiana VIE | | - |
Entergy Texas | $2003.25% Series G due July 2017 | | -$25 million |
| System Energy | $200 VIE | | -6.29% Series F due September 2013 | | $70 million |
| System Energy VIE | | 5.33% Series G due April 2015 | | $60 million |
| System Energy VIE | | 4.02% Series H due February 2017 | | $50 million |
In accordance with regulatory treatment, interest on the nuclear fuel company variable interest entities’ credit facilities, commercial paper, and long-term notes payable is reported in fuel expense.
In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States Louisiana nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through May 2013, September 2014, January 2015, and November 2013, respectively, for issuances by its nuclear fuel company variable interest entity.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 5. LONG - - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Long-term debt for Entergy Corporation and subsidiaries as of December 31, 20092012 and 20082011 consisted of:
| | 2009 | | 2008 |
| | (In Thousands) |
| Mortgage Bonds: | | | |
Libor + 0.40% Series due December 2009-Entergy Gulf States Louisiana (f) | $- | | $219,470 |
4.5% Series due June 2010 - Entergy Arkansas | 100,000 | | 100,000 |
4.67% Series due June 2010 - Entergy Louisiana | 55,000 | | 55,000 |
4.98% Series due July 2010 - Entergy New Orleans | 30,000 | | 30,000 |
5.12% Series due August 2010 - Entergy Gulf States Louisiana (f) | - | | 100,000 |
5.83% Series due November 2010 - Entergy Louisiana | 150,000 | | 150,000 |
4.65% Series due May 2011 - Entergy Mississippi | 80,000 | | 80,000 |
4.875% Series due November 2011 - Entergy Gulf States Louisiana (f) | 200,000 | | 200,000 |
6.2% Series due October 2012 - System Energy | 70,000 | | 70,000 |
6.0% Series due December 2012 - Entergy Gulf States Louisiana (f) | - | | 140,000 |
5.15% Series due February 2013 - Entergy Mississippi | 100,000 | | 100,000 |
5.40% Series due August 2013 - Entergy Arkansas | 300,000 | | 300,000 |
5.25% Series due August 2013 - Entergy New Orleans | 70,000 | | 70,000 |
5.09% Series due November 2014 - Entergy Louisiana | 115,000 | | 115,000 |
5.6% Series due December 2014 - Entergy Gulf States Louisiana (f) | - | | 50,000 |
5.70% Series due June 2015 - Entergy Gulf States Louisiana (f) | 200,000 | | 200,000 |
5.25% Series due August 2015 - Entergy Gulf States Louisiana (f) | 92,120 | | 200,000 |
5.56% Series due September 2015 - Entergy Louisiana | 100,000 | | 100,000 |
5.92% Series due February 2016 - Entergy Mississippi | 100,000 | | 100,000 |
6.75% Series due October 2017 - Entergy New Orleans | 25,000 | | 25,000 |
5.4% Series due May 2018 - Entergy Arkansas | 150,000 | | 150,000 |
6.0% Series due May 2018 - Entergy Gulf States Louisiana | 375,000 | | 375,000 |
4.95% Series due June 2018 - Entergy Mississippi | 95,000 | | 95,000 |
5.0% Series due July 2018 - Entergy Arkansas | 115,000 | | 115,000 |
6.50% Series due September 2018 - Entergy Louisiana | 300,000 | | 300,000 |
7.125% Series due February 2019 - Entergy Texas | 500,000 | | - |
5.5% Series due April 2019 - Entergy Louisiana | 100,000 | | 100,000 |
6.64% Series due July 2019 - Entergy Mississippi | 150,000 | | - |
5.6% Series due September 2024 - Entergy New Orleans | 34,097 | | 34,430 |
5.59% Series due October 2024 - Entergy Gulf States Louisiana | 300,000 | | - |
5.40% Series due November 2024 - Entergy Louisiana | 400,000 | | - |
5.66% Series due February 2025 - Entergy Arkansas | 175,000 | | 175,000 |
5.65% Series due September 2029 - Entergy New Orleans | 38,950 | | 39,345 |
6.7% Series due April 2032 - Entergy Arkansas | 100,000 | | 100,000 |
7.6% Series due April 2032 - Entergy Louisiana | 150,000 | | 150,000 |
6.0% Series due November 2032 - Entergy Arkansas | 100,000 | | 100,000 |
6.0% Series due November 2032 - Entergy Mississippi | 75,000 | | 75,000 |
7.25% Series due December 2032 - Entergy Mississippi | 100,000 | | 100,000 |
5.9% Series due June 2033 - Entergy Arkansas | 100,000 | | 100,000 |
6.20% Series due July 2033 - Entergy Gulf States Louisiana (f) | 240,000 | | 240,000 |
6.25% Series due April 2034 - Entergy Mississippi | 100,000 | | 100,000 |
6.4% Series due October 2034 - Entergy Louisiana | 70,000 | | 70,000 |
6.38% Series due November 2034 - Entergy Arkansas | 60,000 | | 60,000 |
6.18% Series due March 2035 - Entergy Gulf States Louisiana (f) | 85,000 | | 85,000 |
6.30% Series due September 2035 - Entergy Louisiana | 100,000 | | 100,000 |
Type of Debt and Maturity | | Weighted Average Interest Rate December 31, 2012 | | Interest Rate Ranges at December 31, | | Outstanding at December 31, |
2012 | | 2011 | 2012 | | 2011 |
| | | | | | | | | (In Thousands) |
| | | | | | | | | | | |
| Mortgage Bonds | | | | | | | | | | |
| 2012-2017 | | 3.24% | | 1.88%-5.40% | | 3.25%-6.20% | | $1,045,000 | | $865,000 |
| 2018-2022 | | 5.15% | | 3.30%-7.13% | | 3.75%-7.13% | | 2,635,000 | | 2,435,000 |
| 2023-2027 | | 4.82% | | 3.10%-5.66% | | 4.44%-5.66% | | 1,658,369 | | 1,158,449 |
| 2028-2037 | | 6.18% | | 5.65%-6.40% | | 5.65%-6.40% | | 867,976 | | 868,145 |
| 2039-2052 | | 6.22% | | 4.90%-7.88% | | 5.75%-7.88% | | 1,335,000 | | 905,000 |
| | | | | | | | | | | |
| Governmental Bonds (a) | | | | | | | | | | |
| 2012-2017 | | 4.15% | | 2.88%-4.60% | | 2.88%-5.80% | | 86,655 | | 97,495 |
| 2018-2022 | | 5.59% | | 4.60%-5.88% | | 4.60%-5.9% | | 307,030 | | 410,005 |
| 2023-2030 | | 5.00% | | 5.00% | | 5.0%-6.20% | | 198,680 | | 248,680 |
| | | | | | | | | | | |
| Securitization Bonds | | | | | | | | | | |
| 2013-2020 | | 4.18% | | 2.12%-5.79% | | 2.12%-5.79% | | 357,577 | | 416,899 |
| 2021-2023 | | 3.74% | | 2.04%-5.93% | | 2.04%-5.93% | | 616,159 | | 653,948 |
| | | | | | | | | | | |
| Variable Interest Entities Notes Payable (Note 4) | | | | | | | | |
| 2012-2017 | | 3.85% | | 2.62%-9.00% | | 2.25%-9.00% | | 640,000 | | 519,400 |
| | | | | | | | | | | |
| Entergy Corporation Notes | | | | | | | | | | |
| due September 2015 | | n/a | | 3.625% | | 3.625% | | 550,000 | | 550,000 |
| due January 2017 | | n/a | | 4.7% | | n/a | | 500,000 | | - |
| due September 2020 | | n/a | | 5.125% | | 5.125% | | 450,000 | | 450,000 |
| | | | | | | | | | | |
| Note Payable to NYPA | | (b) | | (b) | | (b) | | 109,679 | | 133,363 |
| 5 Year Credit Facility (Note 4) | | n/a | | 2.04% | | 0.75% | | 795,000 | | 1,920,000 |
| Long-term DOE Obligation (c) | | - | | - | | - | | 181,157 | | 181,031 |
| Waterford 3 Lease Obligation (d) | | n/a | | 7.45% | | 7.45% | | 162,949 | | 188,255 |
| Grand Gulf Lease Obligation (d) | | n/a | | 5.13% | | 5.13% | | 138,893 | | 178,784 |
Bank Credit Facility – Entergy Louisiana | | n/a | | n/a | | 0.67% | | - | | 50,000 |
| Unamortized Premium and Discount - Net | | | | | | (10,744) | | (9,531) |
| Other | | | | | | | | 14,454 | | 16,523 |
| Total Long-Term Debt | | | | | | | | 12,638,834 | | 12,236,446 |
| Less Amount Due Within One Year | | | | | | 718,516 | | 2,192,733 |
| Long-Term Debt Excluding Amount Due Within One Year | | | | $11,920,318 | | $10,043,713 |
| | | | | | | | | | | |
| Fair Value of Long-Term Debt (e) | | | | | | $12,849,330 | | $12,176,251 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2009 | | 2008 |
| | (In Thousands) |
| | | | |
7.875% Series due June 2039 - Entergy Texas | 150,000 | | - |
Total mortgage bonds | 5,950,167 | | 5,068,245 |
| Governmental Bonds (a): | | | |
5.45% Series due 2010, Calcasieu Parish - Louisiana (f) | $11,975 | | $22,095 |
6.75% Series due 2012, Calcasieu Parish - Louisiana (f) | 26,170 | | 48,285 |
6.7% Series due 2013, Pointe Coupee Parish - Louisiana (f) | 9,460 | | 17,450 |
5.7% Series due 2014, Iberville Parish - Louisiana (f) | 11,710 | | 21,600 |
5.8% Series due 2015, West Feliciana Parish - Louisiana (f) | 15,395 | | 28,400 |
7.0% Series due 2015, West Feliciana Parish - Louisiana (f) | 16,600 | | 39,000 |
5.8% Series due 2016, West Feliciana Parish - Louisiana (f) | 20,000 | | 20,000 |
6.3% Series due 2016, Pope County - Arkansas (b) | 19,500 | | 19,500 |
4.6% Series due 2017, Jefferson County - Arkansas (b) | 54,700 | | 54,700 |
6.3% Series due 2020, Pope County - Arkansas | 120,000 | | 120,000 |
5.0% Series due 2021, Independence County – Arkansas (b) | 45,000 | | 45,000 |
5.875% Series due 2022, Mississippi Business Finance Corp. | 216,000 | | 216,000 |
5.9% Series due 2022, Mississippi Business Finance Corp. | 102,975 | | 102,975 |
4.9% Series due 2022, Independence County - Mississippi (b) | 30,000 | | 30,000 |
4.6% Series due 2022, Mississippi Business Finance Corp. (b) | 16,030 | | 16,030 |
6.2% Series due 2026, Claiborne County - Mississippi | 90,000 | | 90,000 |
6.6% Series due 2028, West Feliciana Parish - Louisiana (f) | 21,680 | | 40,000 |
Total governmental bonds | 827,195 | | 931,035 |
| Other Long-Term Debt: | | | |
Note Payable to NYPA, non-interest bearing, 4.8% implicit rate | $177,543 | | $198,127 |
5 year Bank Credit Facility, weighted avg rate 1.377% (Note 4) | 2,566,150 | | 3,237,434 |
Bank term loan, Entergy Corporation, avg rate 1.41%, due 2010 | 60,000 | | 60,000 |
7.75% Notes due December 2009, Entergy Corporation | - | | 267,000 |
6.58% Notes due May 2010, Entergy Corporation | 75,000 | | 75,000 |
6.9% Notes due November 2010, Entergy Corporation | 140,000 | | 140,000 |
7.625% Notes initially due February 2011, Entergy Corporation (c) | - | | 500,000 |
7.06% Notes due March 2011, Entergy Corporation | 86,000 | | 86,000 |
Long-term DOE Obligation (d) | 180,683 | | 180,428 |
Waterford 3 Lease Obligation 7.45% (Note 10) | 241,128 | | 247,725 |
Grand Gulf Lease Obligation 5.13% (Note 10) | 266,864 | | 295,304 |
5.51% Series Senior Secured, Series A due October 2013, Entergy GulfStates Reconstruction Funding | 56,728 | | 74,444 |
5.79% Series Senior Secured, Series A due October 2018, Entergy GulfStates Reconstruction Funding | 121,600 | | 121,600 |
5.93% Series Senior Secured, Series A due June 2022, Entergy GulfStates Reconstruction Funding | 114,400 | | 114,400 |
2.12% Series Senior Secured due February 2016, Entergy Texas RestorationFunding, LLC | 182,500 | | - |
3.65% Series Senior Secured due August 2019, Entergy Texas RestorationFunding, LLC | 144,800 | | - |
4.38% Series Senior Secured due November 2023, Entergy Texas RestorationFunding, LLC | 218,600 | | - |
Bank Credit Facility, weighted avg rate 2.285% (Note 4) - Entergy Texas | - | | 100,000 |
Unamortized Premium and Discount - Net | (10,635) | | (6,906) |
Other | 18,972 | | 28,913 |
| Total Long-Term Debt | 11,417,695 | | 11,718,749 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2009 | | 2008 |
| | (In Thousands) |
| | | | |
| Less Amount Due Within One Year | 711,957 | | 544,460 |
| | | | |
| Long-Term Debt Excluding Amount Due Within One Year | $10,705,738 | | $11,174,289 |
| | | | |
| Fair Value of Long-Term Debt (e) | $10,727,908 | | $10,117,865 |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
| (b) | The bonds are secured byThese notes do not have a seriesstated interest rate, but have an implicit interest rate of collateral first mortgage bonds.4.8%. |
| (c) | In December 2005, Entergy Corporation sold 10 million equity units with a stated amount of $50 each. An equity unit consisted of (1) a note, initially due February 2011 and initially bearing interest at an annual rate of 5.75%, and (2) a purchase contract that obligated the holder of the equity unit to purchase for $50 between 0.5705 and 0.7074 shares of Entergy Corporation common stock on or before February 17, 2009. Entergy paid the holders quarterly contract adjustment payments of 1.875% per year on the stated amount of $50 per equity unit. Under the terms of the purchase contracts, Entergy attempted to remarket the notes in February 2009 but was unsuccessful, the note holders put the notes to Entergy, Entergy retired the notes, and Entergy issued 6,598,000 shares of common stock in the settlement of the purchase contracts. |
(d) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy'sEntergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt. |
| (d) | See Note 10 for further discussion of the Waterford 3 and Grand Gulf Lease Obligations. |
| (e) | The fair value excludes lease obligations of $241$163 million at Entergy Louisiana and $267$139 million at System Energy, long-term DOE obligations of $181 million at Entergy Arkansas, and the note payable to NYPA of $178$110 million at Entergy, and includes debt due within one year. It is determined using bidFair values are classified as Level 2 in the fair value hierarchy discussed in Note 16 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported by dealer markets and by nationally recognized investment banking firms. |
(f) | Entergy Gulf States Louisiana remains primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007 and has not been subsequently repaid. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed approximately 46% of this long-term debt.trades. |
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2009,2012, for the next five years are as follows:
| | Amount |
| | (In Thousands) |
| | |
| 2010 | $652,916 |
| 2011 | $394,778 |
| 2012 | $2,689,454 |
| 2013 | $554,154 |
| 2014 | $144,920 |
| | Amount |
| | (In Thousands) |
| | |
| 2013 | $659,720 |
| 2014 | $385,373 |
| 2015 | $860,566 |
| 2016 | $295,441 |
| 2017 | $1,561,801 |
In November 2000, Entergy's Non-Utility NuclearEntergy’s non-utility nuclear business purchased the FitzPatrick and Indian Point 3 power plants in a seller-financed transaction. Entergy issued notes to NYPA with seven annual installments of approximately $108 million commencing one year from the date of the closing, and eight annual installments of $20 million commencing eight years from the date of the closing. These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. In accordance with the purchase agreement with NYPA, the purchase of Indian Point 2 in 2001 resulted in Entergy's Non-Utility Nuclear businessEntergy becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2003. This liability was recorded upon the purchase of Indian Point 2 in September 2001, and is included in the note payable to NYPA balance above. In July 2003 a payment of $102 million was made prior to maturity on the note payable to NYPA. Under a provision in a letter of credit supporting these notes, if certain of the Utility operating companies or System Energy were to default on other indebtedness, Entergy could be required to post collateral to support the letter of credit.
Covenants in the Entergy Corporation notes require it to maintain a consolidated debt ratio of 65% or less of its total capitalization. If Entergy's debt ratio exceeds this limit, or if Entergy Corporation or certain of the Utility operating companies default on other indebtedness or are in bankruptcy or insolvency proceedings, an acceleration of the notes' maturity dates may occur.
Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have received FERCobtained long-term financing orders authorizing long-term securities issuances.authorizations from the FERC that extend through July 2013. Entergy Arkansas has received an APSCobtained long-term financing order authorizing long-term securities issuances. The long-term securities issuances ofauthorization from the APSC that extends through December 2015. Entergy New Orleans are limited to amounts authorized byhas obtained long-term financing authorization from the City Council and the current authorizationthat extends through August 2010.July 2014.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
| · | maintain System Energy'sEnergy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt); |
| · | permit the continued commercial operation of Grand Gulf; |
| · | pay in full all System Energy indebtedness for borrowed money when due; and |
| · | enable System Energy to make payments on specific System Energy debt, under supplements to the agreement assigning System Energy'sEnergy’s rights in the agreement as security for the specific debt. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Long-term debt for the Registrant Subsidiaries as of December 31, 20092012 and 20082011 consisted of:
| | 2009 | | 2008 | 2012 | | 2011 |
| | (In Thousands) | (In Thousands) |
| Entergy Arkansas | | | | | | |
Mortgage Bonds: | | | | | | |
4.50% Series due June 2010 | $100,000 | | $100,000 | |
5.40% Series due August 2013 | 300,000 | | 300,000 | $300,000 | | $300,000 |
5.4% Series due May 2018 | 150,000 | | 150,000 | |
5.0% Series due July 2018 | 115,000 | | 115,000 | 115,000 | | 115,000 |
3.75% Series due February 2021 | | 350,000 | | 350,000 |
5.66% Series due February 2025 | 175,000 | | 175,000 | 175,000 | | 175,000 |
6.7% Series due April 2032 | 100,000 | | 100,000 | |
6.0% Series due November 2032 | 100,000 | | 100,000 | |
5.9% Series due June 2033 | 100,000 | | 100,000 | 100,000 | | 100,000 |
6.38% Series due November 2034 | 60,000 | | 60,000 | 60,000 | | 60,000 |
5.75% Series due November 2040 | | 225,000 | | 225,000 |
4.9% Series due December 2052 | | 200,000 | | - |
Total mortgage bonds | 1,200,000 | | 1,200,000 | 1,525,000 | | 1,325,000 |
| | | | | | | |
Governmental Bonds (a): | | | | | | |
6.3% Series due 2016, Pope County (d) | 19,500 | | 19,500 | |
4.6% Series due 2017, Jefferson County (d) | 54,700 | | 54,700 | 54,700 | | 54,700 |
6.3% Series due 2020, Pope County | 120,000 | | 120,000 | |
5.0% Series due 2021, Independence County (d) | 45,000 | | 45,000 | 45,000 | | 45,000 |
Total governmental bonds | 239,200 | | 239,200 | 99,700 | | 99,700 |
| | | | | | | |
Other Long-Term Debt | | | | |
Variable Interest Entity Notes Payable (Note 4): | | | | |
9% Series H due June 2013 | | 30,000 | | 30,000 |
| 5.69% Series I due July 2014 | | 70,000 | | 70,000 |
3.23% Series J due July 2016 | | 55,000 | | 55,000 |
2.62% Series K due December 2017 | | 60,000 | | - |
Total variable interest entity notes payable | | 215,000 | | 155,000 |
| | | | | |
Securitization Bonds: | | | | |
2.30% Series Senior Secured due August 2021 | | 101,575 | | 113,792 |
Total securitization bonds | | 101,575 | | 113,792 |
| | | | | |
Other: | | | | |
Long-term DOE Obligation (b) | 180,683 | | 180,428 | 181,157 | | 181,031 |
Unamortized Premium and Discount – Net | (1,314) | | (1,457) | (655) | | (733) |
Other | | 2,118 | | 2,131 |
| | | | | | | |
Total Long-Term Debt | 1,618,569 | | 1,618,171 | 2,123,895 | | 1,875,921 |
Less Amount Due Within One Year | 100,000 | | - | 330,000 | | - |
Long-Term Debt Excluding Amount Due Within One Year | $1,518,569 | | $1,618,171 | $1,793,895 | | $1,875,921 |
| | | | | | | |
Fair Value of Long-Term Debt (c) | $1,463,378 | | $1,306,382 | $1,876,335 | | $1,756,361 |
| | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2012 | | 2011 |
| | (In Thousands) |
| Entergy Gulf States Louisiana | | | |
Mortgage Bonds: | | | |
6.0% Series due May 2018 | $375,000 | | $375,000 |
3.95% Series due October 2020 | 250,000 | | 250,000 |
5.59% Series due October 2024 | 300,000 | | 300,000 |
6.2% Series due July 2033 | 240,000 | | 240,000 |
6.18% Series due March 2035 | 85,000 | | 85,000 |
Total mortgage bonds | 1,250,000 | | 1,250,000 |
| | | | |
Governmental Bonds (a): | | | |
2.875% Series due 2015, Louisiana Public Facilities Authority (d) | 31,955 | | 31,955 |
5.8% Series due 2016, West Feliciana Parish | - | | 10,840 |
5.0% Series due 2028, Louisiana Public Facilities Authority (d) | 83,680 | | 83,680 |
Total governmental bonds | 115,635 | | 126,475 |
| | | | |
Variable Interest Entity Notes Payable (Note 4): | | | |
5.41% Series O due July 2012 | - | | 60,000 |
5.56% Series N due May 2013 | 75,000 | | 75,000 |
3.25% Series Q due July 2017 | 75,000 | | - |
Credit Facility due July 2013, weighted avg rate 2.25% | - | | 29,400 |
Total variable interest entity notes payable | 150,000 | | 164,400 |
| | | | |
Other: | | | |
Unamortized Premium and Discount – Net | (1,810) | | (2,048) |
Other | 3,604 | | 3,603 |
| | | | |
Total Long-Term Debt | 1,517,429 | | 1,542,430 |
Less Amount Due Within One Year | 75,000 | | 60,000 |
Long-Term Debt Excluding Amount Due Within One Year | $1,442,429 | | $1,482,430 |
| | | | |
Fair Value of Long-Term Debt (c) | $1,668,819 | | $1,642,388 |
| | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2009 | | 2008 |
| | (In Thousands) |
| Entergy Gulf States Louisiana | | | |
Mortgage Bonds: | | | |
Libor + 0.4% Series due December 2009 (e) | $- | | $219,470 |
5.12% Series due August 2010 (e) | - | | 100,000 |
4.875% Series due November 2011 (e) | 200,000 | | 200,000 |
6.0% Series due December 2012 (e) | - | | 140,000 |
5.6% Series due December 2014 (e) | - | | 50,000 |
5.70% Series due June 2015 (e) | 200,000 | | 200,000 |
5.25% Series due August 2015 (e) | 92,120 | | 200,000 |
6.00% Series due May 2018 | 375,000 | | 375,000 |
5.59% Series due October 2024 | 300,000 | | - |
6.2% Series due July 2033 (e) | 240,000 | | 240,000 |
6.18% Series due March 2035 (e) | 85,000 | | 85,000 |
Total mortgage bonds | 1,492,120 | | 1,809,470 |
| | | | |
Governmental Bonds (a) (e): | | | |
5.45% Series due 2010, Calcasieu Parish | 11,975 | | 22,095 |
6.75% Series due 2012, Calcasieu Parish | 26,170 | | 48,285 |
6.7% Series due 2013, Pointe Coupee Parish | 9,460 | | 17,450 |
5.7% Series due 2014, Iberville Parish | 11,710 | | 21,600 |
5.8% Series due 2015, West Feliciana Parish | 15,395 | | 28,400 |
7.0% Series due 2015, West Feliciana Parish | 16,600 | | 39,000 |
5.8% Series due 2016, West Feliciana Parish | 20,000 | | 20,000 |
6.6% Series due 2028, West Feliciana Parish | 21,680 | | 40,000 |
Total governmental bonds | 132,990 | | 236,830 |
| | | | |
Other Long-Term Debt | | | |
Unamortized Premium and Discount - Net | (2,372) | | (2,574) |
Other | 3,603 | | 3,603 |
| | | | |
Total Long-Term Debt | 1,626,341 | | 2,047,329 |
Less Amount Due Within One Year | 11,975 | | 219,470 |
Long-Term Debt Excluding Amount Due Within One Year | $1,614,366 | | $1,827,859 |
| | | | |
Fair Value of Long-Term Debt (c) | $1,637,862 | | $1,871,421 |
| | | | |
| | 2012 | | 2011 |
| | (In Thousands) |
| Entergy Louisiana | | | |
Mortgage Bonds: | | | |
1.875% Series due December 2014 | $250,000 | | $- |
6.50% Series due September 2018 | 300,000 | | 300,000 |
4.8% Series due May 2021 | 200,000 | | 200,000 |
3.3% Series due December 2022 | 200,000 | | - |
5.40% Series due November 2024 | 400,000 | | 400,000 |
4.44% Series due January 2026 | 250,000 | | 250,000 |
6.4% Series due October 2034 | 70,000 | | 70,000 |
6.3% Series due September 2035 | 100,000 | | 100,000 |
6.0% Series due March 2040 | 150,000 | | 150,000 |
5.875% Series due June 2041 | 150,000 | | 150,000 |
5.25% Series due July 2052 | 200,000 | | - |
Total mortgage bonds | 2,270,000 | | 1,620,000 |
| | | | |
Governmental Bonds (a): | | | |
5.0% Series due 2030, Louisiana Public Facilities Authority (d) | 115,000 | | 115,000 |
Total governmental bonds | 115,000 | | 115,000 |
| | | | |
Variable Interest Entity Notes Payable (Note 4): | | | |
5.69% Series E due July 2014 | 50,000 | | 50,000 |
3.30% Series F due March 2016 | 20,000 | | 20,000 |
3.25% Series G due July 2017 | 25,000 | | - |
Total variable interest entity notes payable | 95,000 | | 70,000 |
| | | | |
Securitization Bonds: | | | |
2.04% Series Senior Secured due June 2021 | 181,584 | | 207,156 |
Total securitization bonds | 181,584 | | 207,156 |
| | | | |
Other: | | | |
Waterford 3 Lease Obligation 7.45% (Note 10) | 162,949 | | 188,255 |
Bank Credit Facility, weighted average rate 0.67% (Note 4) | - | | 50,000 |
Unamortized Premium and Discount - Net | (2,230) | | (1,912) |
Other | 3,792 | | 3,813 |
| | | | |
| Total Long-Term Debt | 2,826,095 | | 2,252,312 |
| Less Amount Due Within One Year | 14,236 | | 75,309 |
| Long-Term Debt Excluding Amount Due Within One Year | $2,811,859 | | $2,177,003 |
| | | | |
| Fair Value of Long-Term Debt (c) | $2,921,322 | | $2,211,355 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2012 | | 2011 |
| | (In Thousands) |
| Entergy Mississippi | | | |
Mortgage Bonds: | | | |
5.15% Series due February 2013 | $100,000 | | $100,000 |
3.25% Series due June 2016 | 125,000 | | 125,000 |
4.95% Series due June 2018 | 95,000 | | 95,000 |
6.64% Series due July 2019 | 150,000 | | 150,000 |
3.1% Series due July 2023 | 250,000 | | - |
6.0% Series due November 2032 | 75,000 | | 75,000 |
6.25% Series due April 2034 | 100,000 | | 100,000 |
6.20% Series due April 2040 | 80,000 | | 80,000 |
6.0% Series due May 2051 | 150,000 | | 150,000 |
Total mortgage bonds | 1,125,000 | | 875,000 |
| | | | |
Governmental Bonds (a): | | | |
4.60% Series due 2022, Mississippi Business Finance Corp.(d) | 16,030 | | 16,030 |
4.90% Series due 2022, Independence County (d) | 30,000 | | 30,000 |
Total governmental bonds | 46,030 | | 46,030 |
| | | | |
Other: | | | |
Unamortized Premium and Discount – Net | (1,511) | | (591) |
| | | | |
| Total Long-Term Debt | 1,169,519 | | 920,439 |
| Less Amount Due Within One Year | 100,000 | | - |
| Long-Term Debt Excluding Amount Due Within One Year | $1,069,519 | | $920,439 |
| | | | |
| Fair Value of Long-Term Debt (c) | $1,230,714 | | $985,600 |
| | 2009 | | 2008 |
| | (In Thousands) |
| Entergy Louisiana | | | |
Mortgage Bonds: | | | |
4.67% Series due June 2010 | $55,000 | | $55,000 |
5.83% Series due November 2010 | 150,000 | | 150,000 |
5.09% Series due November 2014 | 115,000 | | 115,000 |
5.56% Series due September 2015 | 100,000 | | 100,000 |
6.50% Series due September 2018 | 300,000 | | 300,000 |
5.5% Series due April 2019 | 100,000 | | 100,000 |
5.40% Series due November 2024 | 400,000 | | - |
7.6% Series due April 2032 | 150,000 | | 150,000 |
6.4% Series due October 2034 | 70,000 | | 70,000 |
6.3% Series due September 2035 | 100,000 | | 100,000 |
Total mortgage bonds | 1,540,000 | | 1,140,000 |
| | | | |
| Other Long-Term Debt: | | | |
Waterford 3 Lease Obligation 7.45% (Note 10) | 241,128 | | 247,725 |
Unamortized Premium and Discount - Net | (1,576) | | (252) |
| | | | |
| Total Long-Term Debt | 1,779,552 | | 1,387,473 |
| Less Amount Due Within One Year | 222,326 | | - |
| Long-Term Debt Excluding Amount Due Within One Year | $1,557,226 | | $1,387,473 |
| | | | |
| Fair Value of Long-Term Debt (c) | $1,565,969 | | $1,085,155 |
| | 2012 | | 2011 |
| | (In Thousands) |
| Entergy New Orleans | | | |
Mortgage Bonds: | | | |
5.25% Series due August 2013 | $70,000 | | $70,000 |
5.10% Series due December 2020 | 25,000 | | 25,000 |
5.6% Series due September 2024 | 33,369 | | 33,449 |
5.65% Series due September 2029 | 37,976 | | 38,145 |
5.0% Series due December 2052 | 30,000 | | - |
Total mortgage bonds | 196,345 | | 166,594 |
| | | | |
Other: | | | |
Unamortized Premium and Discount – Net | (45) | | (57) |
| | | | |
| Total Long-Term Debt | 196,300 | | 166,537 |
| Less Amount Due Within One Year | 70,000 | | - |
| Long-Term Debt Excluding Amount Due Within One Year | $126,300 | | $166,537 |
| | | | |
| Fair Value of Long-Term Debt (c) | $200,725 | | $169,270 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2009 | | 2008 |
| | (In Thousands) |
| Entergy Mississippi | | | |
Mortgage Bonds: | | | |
4.65% Series due May 2011 | $80,000 | | $80,000 |
5.15% Series due February 2013 | 100,000 | | 100,000 |
5.92% Series due February 2016 | 100,000 | | 100,000 |
4.95% Series due June 2018 | 95,000 | | 95,000 |
6.64% Series due July 2019 | 150,000 | | - |
6.0% Series due November 2032 | 75,000 | | 75,000 |
7.25% Series due December 2032 | 100,000 | | 100,000 |
6.25% Series due April 2034 | 100,000 | | 100,000 |
Total mortgage bonds | 800,000 | | 650,000 |
| | | | |
Governmental Bonds (a): | | | |
4.60% Series due 2022, Mississippi Business Finance Corp.(d) | 16,030 | | 16,030 |
4.90% Series due 2022, Independence County (d) (f) | 30,000 | | 30,000 |
Total governmental bonds | 46,030 | | 46,030 |
| | | | |
| Other Long-Term Debt: | | | |
Unamortized Premium and Discount - Net | (726) | | (700) |
| | | | |
| Total Long-Term Debt | 845,304 | | 695,330 |
| Less Amount Due Within One Year | - | | - |
| Long-Term Debt Excluding Amount Due Within One Year | $845,304 | | $695,330 |
| | | | |
| Fair Value of Long-Term Debt (c) | $874,131 | | $629,227 |
| | 2009 | | 2008 |
| | (In Thousands) |
| Entergy New Orleans | | | |
Mortgage Bonds: | | | |
4.98% Series due July 2010 | $30,000 | | $30,000 |
5.25% Series due August 2013 | 70,000 | | 70,000 |
6.75% Series due October 2017 | 25,000 | | 25,000 |
5.6% Series due September 2024 | 34,097 | | 34,430 |
5.65% Series due September 2029 | 38,950 | | 39,345 |
Total mortgage bonds | 198,047 | | 198,775 |
| | | | |
| Other Long-Term Debt: | | | |
Affiliate Notes Payable (g) | 74,230 | | 74,230 |
Unamortized Premium and Discount - Net | (24) | | (32) |
| | | | |
| Total Long-Term Debt | 272,253 | | 272,973 |
| Less Amount Due Within One Year | 104,230 | | - |
| Long-Term Debt Excluding Amount Due Within One Year | $168,023 | | $272,973 |
| | | | |
| Fair Value of Long-Term Debt (c) | $198,062 | | $179,009 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
Entergy Gulf States Louisiana remains primarily liable for allTable of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007 and has not been subsequently repaid. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, of which $168 million remains outstanding at December 31, 2009. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation. Entergy Texas' debt assumption does not discharge Entergy Gulf States Louisiana's liability for the long-term debt. To secure its debt assumption obligations, Entergy Texas granted to Entergy Gulf States Louisiana a first lien on Entergy Texas' assets that were previously subject to the Entergy Gulf States, Inc. mortgage. Entergy Texas has until December 31, 2010 to repay the assumed debt. Following is the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2009 and 2008 and Entergy Texas' pro rata share of that debt. Also included are the mortgage bonds issued by Entergy Texas and the securitization bonds issued by Entergy Gulf States Reconstruction Funding and by Entergy Texas Restoration Funding, LLC that are described in further detail below in this Note.
| | 2009 | | 2008 |
| | (In Thousands) |
Mortgage Bonds share assumed under debt assumption agreement: | | | |
Libor + 0.4% Series due December 2009 | $- | | $100,509 |
5.12 % Series due August 2010 | - | | 45,796 |
4.875% Series due November 2011 | 28,023 | | 91,592 |
6.0% Series due December 2012 | - | | 64,114 |
5.6% Series due December 2014 | - | | 22,898 |
5.70% Series due June 2015 | 91,592 | | 91,592 |
5.25% Series due August 2015 | - | | 91,592 |
6.2% Series due July 2033 | - | | 109,911 |
6.18% Series due March 2035 | 38,927 | | 38,927 |
Total mortgage bonds | 158,542 | | 656,931 |
| | | | |
Governmental Bonds share assumed under debt assumption agreement (a): | | | |
5.45% Series due 2010, Calcasieu Parish | - | | 10,120 |
6.75% Series due 2012, Calcasieu Parish | - | | 22,115 |
6.7% Series due 2013, Pointe Coupee Parish | - | | 7,990 |
5.7% Series due 2014, Iberville Parish | - | | 9,890 |
5.8% Series due 2015, West Feliciana Parish | - | | 13,005 |
7.0% Series due 2015, West Feliciana Parish | 40 | | 22,440 |
5.8% Series due 2016, West Feliciana Parish | 9,160 | | 9,160 |
6.6% Series due 2028, West Feliciana Parish | - | | 18,320 |
Total governmental bonds | 9,200 | | 113,040 |
| | | | |
Mortgage Bonds: | | | |
7.125% Series due February 2019 | 500,000 | | - |
7.875% Series due June 2039 | 150,000 | | - |
Total mortgage bonds | 650,000 | | - |
Contents
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2009 | | 2008 | 2012 | | 2011 |
| | (In Thousands) | (In Thousands) |
| Entergy Texas | | | | |
Mortgage Bonds: | | | | |
3.60% Series due June 2015 | | $200,000 | | $200,000 |
7.125% Series due February 2019 | | 500,000 | | 500,000 |
4.1% Series due September 2021 | | 75,000 | | 75,000 |
7.875% Series due June 2039 | | 150,000 | | 150,000 |
Total mortgage bonds | | 925,000 | | 925,000 |
| | | | | | | |
Other Long-Term Debt: | | | | |
Securitization Bonds: | | | | |
5.51% Series Senior Secured, Series A due October 2013 | 56,728 | | 74,444 | - | | 18,494 |
2.12% Series Senior Secured due February 2016 | | 93,436 | | 132,005 |
5.79% Series Senior Secured, Series A due October 2018 | 121,600 | | 121,600 | 119,341 | | 121,600 |
3.65% Series Senior Secured due August 2019 | | 144,800 | | 144,800 |
5.93% Series Senior Secured, Series A due June 2022 | 114,400 | | 114,400 | 114,400 | | 114,400 |
2.12% Series Senior Secured due February 2016 | 182,500 | | - | |
3.65% Series Senior Secured due August 2019 | 144,800 | | - | |
4.38% Series Senior Secured due November 2023 | 218,600 | | - | 218,600 | | 218,600 |
Bank Credit Facility, weighted avg rate 2.285% (Note 4) | - | | 100,000 | |
Total securitization bonds | | 690,577 | | 749,899 |
| | | | | |
Other: | | | | |
Unamortized Premium and Discount - Net | (3,759) | | (952) | (2,653) | | (3,103) |
Other | 5,414 | | 5,414 | 4,889 | | 5,331 |
| | | | | | | |
Total Long-Term Debt | 1,658,025 | | 1,184,877 | 1,617,813 | | 1,677,127 |
Less Amount Due Within One Year | 167,742 | | 100,509 | - | | - |
Long-Term Debt Excluding Amount Due Within One Year | $1,490,283 | | $1,084,368 | $1,617,813 | | $1,677,127 |
| | | | | | | |
Fair Value of Long-Term Debt (c) | $1,747,348 | | $1,085,362 | $1,885,672 | | $1,906,081 |
| | | | | |
| | 2009 | | 2008 |
| | (In Thousands) |
| System Energy | | | |
Mortgage Bonds: | | | |
6.2% Series due October 2012 | $70,000 | | $70,000 |
Total mortgage bonds | 70,000 | | 70,000 |
| | | | |
Governmental Bonds (a): | | | |
5.875% Series due 2022, Mississippi Business Finance Corp. | 216,000 | | 216,000 |
5.9% Series due 2022, Mississippi Business Finance Corp. | 102,975 | | 102,975 |
6.2% Series due 2026, Claiborne County | 90,000 | | 90,000 |
Total governmental bonds | 408,975 | | 408,975 |
| | | | |
| Other Long-Term Debt: | | | |
Grand Gulf Lease Obligation 5.13% (Note 10) | 266,864 | | 295,304 |
Unamortized Premium and Discount - Net | (864) | | (939) |
| | | | |
| Total Long-Term Debt | 744,975 | | 773,340 |
| Less Amount Due Within One Year | 41,715 | | 28,440 |
| Long-Term Debt Excluding Amount Due Within One Year | $703,260 | | $744,900 |
| | | | |
| Fair Value of Long-Term Debt (c) | $479,893 | | $363,515 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | 2012 | | 2011 |
| | (In Thousands) |
| System Energy | | | |
Mortgage Bonds: | | | |
6.2% Series due October 2012 | $- | | $70,000 |
4.1% Series due April 2023 | 250,000 | | - |
Total mortgage bonds | 250,000 | | 70,000 |
| | | | |
Governmental Bonds (a): | | | |
5.875% Series due 2022, Mississippi Business Finance Corp. | 216,000 | | 216,000 |
5.9% Series due 2022, Mississippi Business Finance Corp. | - | | 102,975 |
6.2% Series due 2026, Claiborne County | - | | 50,000 |
Total governmental bonds | 216,000 | | 368,975 |
| | | | |
Variable Interest Entity Notes Payable (Note 4): | | | |
6.29% Series F due September 2013 | 70,000 | | 70,000 |
5.33% Series G due April 2015 | 60,000 | | 60,000 |
4.02% Series H due February 2017 | 50,000 | | - |
Total variable interest entity notes payable | 180,000 | | 130,000 |
| | | | |
Other: | | | |
Grand Gulf Lease Obligation 5.13% (Note 10) | 138,893 | | 178,784 |
Unamortized Premium and Discount – Net | (1,096) | | (714) |
Other | 2 | | 3 |
| | | | |
| Total Long-Term Debt | 783,799 | | 747,048 |
| Less Amount Due Within One Year | 111,854 | | 110,163 |
| Long-Term Debt Excluding Amount Due Within One Year | $671,945 | | $636,885 |
| | | | |
| Fair Value of Long-Term Debt (c) | $664,670 | | $582,952 |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
| (b) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy'sEntergy’s nuclear owner/licensee subsidiaries have contracts with the DOE for spent nuclear fuel disposal service. The contracts include a one-time fee for generation prior to April 7, 1983. Entergy Arkansas is the only Entergy company that generated electric power with nuclear fuel prior to that date and includes the one-time fee, plus accrued interest, in long-term debt. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| (c) | The fair value excludes lease obligations of $241$163 million at Entergy Louisiana and $267$139 million at System Energy and long-term DOE obligations of $181 million at Entergy Arkansas, and affiliate notes payable of $74 million at Entergy New Orleans, and includes debt due within one year. It is determined using bidFair values are classified as Level 2 in the fair value hierarchy discussed in Note 16 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported by dealer markets and by nationally recognized investment banking firms.trades. |
| (d) | The bonds are secured by a series of collateral first mortgage bonds. |
(e) | Entergy Gulf States Louisiana remains primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2009 and 2008. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed approximately 46% of this long-term debt. Entergy Gulf States Louisiana recorded an assumption asset on its balance sheet to reflect the long-term debt assumed by Entergy Texas. |
(f) | In April 2008, Entergy Mississippi repurchased its $30 million of Auction Rate Independence County Pollution Control Revenue Bonds due July 2022. In June 2008, Entergy Mississippi remarketed the series and fixed the interest rate to maturity at 4.90%. |
(g) | The affiliate note payable at Entergy New Orleans that is due May 2010 is now classified as current notes payable - associated companies. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations, and affiliate notes payable)obligations) for debt outstanding as of December 31, 2009,2012, for the next five years are as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| 2010 | | $100,000 | | $11,975 | | $205,000 | | - | | $30,000 | | $167,742 | | - |
| 2011 | | - | | $200,000 | | - | | $80,000 | | - | | - | | - |
| 2012 | | - | | $26,170 | | - | | - | | - | | - | | $70,000 |
| 2013 | | $300,000 | | $9,460 | | - | | $100,000 | | $70,000 | | $56,728 | | - |
| 2014 | | - | | $11,710 | | $115,000 | | - | | - | | - | | - |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | |
| 2013 | | $330,000 | | $75,000 | | - | | $100,000 | | $70,000 | | - | | $70,000 |
| 2014 | | $70,000 | | - | | $300,000 | | - | | - | | - | | - |
| 2015 | | - | | $31,955 | | - | | - | | - | | $200,000 | | $60,000 |
| 2016 | | $55,000 | | - | | $20,000 | | $125,000 | | - | | $93,436 | | - |
| 2017 | | $114,700 | | $75,000 | | $25,000 | | - | | - | | - | | $50,000 |
Entergy Arkansas Debt Issuances
In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.
Entergy Arkansas Securitization Bonds
In June 2010, the APSC issued a financing order authorizing the issuance of bonds to recover Entergy Arkansas’s January 2009 ice storm damage restoration costs, including carrying costs of $11.5 million and $4.6 million of up-front financing costs. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. The bonds have a coupon of 2.30% and an expected maturity date of August 2021. Although the principal amount is not due until the date given above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $12.6 million for 2013, $12.8 million for 2014, $13.2 million for 2015, $13.4 million for 2016, and $13.8 million for 2017. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections.
Entergy Louisiana Securitization Bonds – Little Gypsy
In August 2011, the LPSC issued a financing order authorizing the issuance of bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project. In September 2011, Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, issued $207.2 million of senior secured investment recovery bonds. The bonds have an interest rate of 2.04% and an expected maturity date of June 2021. Although the principal amount is not due until the date given above, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $16.6 million for 2013, $21.9 million for 2014, $20.5 million for 2015, $21.6 million for 2016, and $21.7 million for 2017. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an
Entergy Corporation and Subsidiaries
Notes to Financial Statements
investment recovery charge amounts sufficient to service the bonds. In accordance with the financing order, Entergy Louisiana will apply the proceeds it received from the sale of the investment recovery property as a reimbursement for previously-incurred investment recovery costs. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections.
Entergy Texas Securitization Bonds - Hurricane Rita
In April 2007, the PUCT issued a financing order authorizing the issuance of securitization bonds to recover $353 million of Entergy Texas'Texas’s Hurricane Rita reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC, a company that is now wholly-owned and consolidated by Entergy Texas, issued $329.5 million of senior secured transition bonds (securitization bonds), as follows:
| | Amount |
| | (In Thousands) |
| Senior Secured Transition Bonds, Series A: | |
| Tranche A-1 (5.51%) due October 2013 | $93,500 |
| Tranche A-2 (5.79%) due October 2018 | 121,600 |
| Tranche A-3 (5.93%) due June 2022 | 114,400 |
| Total senior secured transition bonds | $329,500 |
Although the principal amount of each tranche is not due until the dates given above, Entergy Gulf States Reconstruction Funding expects to make principal payments on the bonds over the next five years in the amounts of $18.6 million for 2010, $19.7 million for 2011, $20.8 million for 2012, $21.9 million for 2013, and $23.2 million for 2014.2014, $24.6 million for 2015, $26.0 million for 2016, and $27.6 million for 2017. All of the scheduled principal payments for 2010-20122013-2016 are for Tranche A-1, except for $2.3A-2, $23.6 million for Tranche A-2 in 2012, and all of the scheduled principal payments for 2013-20142017 are for Tranche A-2.A-2, and $4 million of the scheduled principal payments for 2017 are for Tranche A-3.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
With the proceeds, Entergy Gulf States Reconstruction Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas began cost recovery through the transition charge in July 2007.balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Gulf States Reconstruction Funding, including the transition property, and the creditors of Entergy Gulf States Reconstruction Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Gulf States Reconstruction Funding except to remit transition charge collections.
Entergy Texas Securitization Bonds - Hurricane Ike and Hurricane Gustav
In September 2009, the PUCT authorized the issuance of securitization bonds to recover $566.4 million of Entergy Texas'Texas’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transitiontransaction costs, offset by insurance proceeds. In November 2009, Entergy Texas Restoration funding, LLC (Entergy Texas Restoration Funding), a company wholly-owned and consolidated by Entergy Texas, issued $545.9 million of senior secured transition bonds (securitization bonds), as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | Amount |
| | (In Thousands) |
| Senior Secured Transition Bonds | |
| Tranche A-1 (2.12%) due February 2016 | $182,500 |
| Tranche A-2 (3.65%) due August 2019 | 144,800 |
| Tranche A-3 (4.38%) due November 2023 | 218,600 |
| Total senior secured transition bonds | $545,900 |
Although the principal amount of each tranche is not due until the dates given above, Entergy Texas Restoration Funding expects to make principal payments on the bonds over the next five years in the amount of $12.7 million for 2010, $37.8 million for 2011, $38.6 million for 2012, $39.4 million for 2013, and $40.2 million for 2014.2014, $41.2 million for 2015, $42.6 million for 2016, and $44.1 million for 2017. All of the expectedscheduled principal payments for 2010-20142013-2014 are for Tranche A-1.A-1, $13.8 million of the scheduled principal payments for 2015 are for Tranche A-1 and $27.4 million are for Tranche A-2, and all of the scheduled principal payments for 2016-2017 are for Tranche A-2.
With the proceeds, Entergy Texas Restoration Funding purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas expects to use the proceeds to reduce debt.balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of Entergy Texas Restoration Funding, including the transition property, and the creditors of Entergy Texas Restoration Funding do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to Entergy Texas Restoration Funding except to remit transition charge collections.
Entergy Texas Note Payable to Entergy Corporation
In December 2008, Entergy Texas borrowed $160 million from its parent company, Entergy Corporation, under a $300 million revolving credit facility pursuant to an Inter-Company Credit Agreement between Entergy Corporation and Entergy Texas. The note had a December 3, 2013 maturity date. Entergy Texas used the proceeds, together with other available corporate funds, to pay at maturity the portion of the $350 million Floating Rate series of First Mortgage Bonds due December 2008 that had been assumed by Entergy Texas, and that bond series is no longer outstanding. In January 2009, Entergy Texas repaid its $160 million note payable to Entergy Corporation with the proceeds from the issuance of $500 million of 7.125% Series mortgage bonds in January 2009.
Entergy New Orleans Affiliate Notes
Pursuant to its plan of reorganization, in May 2007 Entergy New Orleans issued notes due in three years in satisfaction of its affiliate prepetition accounts payable (approximately $74 million, including interest), including its indebtedness to the Entergy System money pool. Entergy New Orleans included in the principal amount of the notes accrued interest from September 23, 2005 at the Louisiana judicial rate of interest for 2005 (6%) and 2006 (8%), and at the Louisiana judicial rate of interest plus 1% for 2007 through the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
date of issuance of the notes. Entergy New Orleans will pay interest on the notes from their date of issuance at the Louisiana judicial rate of interest plus 1%. The Louisiana judicial rate of interest is 9.5% for 2007, 8.5% for 2008, 5.5% for 2009, and 3.5% for 2010.
NOTE 6. PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans)
The number of shares and units authorized and outstanding and dollar value of preferred stock, preferred membership interests, and minoritynon-controlling interest for Entergy Corporation subsidiaries as of December 31, 20092012 and 20082011 are presented below. All series of the Utility preferred stock are redeemable at the option of the related company.
| | | Shares/Units Authorized | | Shares/Units Outstanding | | | | | | Shares/Units Authorized | | Shares/Units Outstanding | | | | |
| | | 2009 | | 2008 | | 2009 | | 2008 | | 2009 | | 2008 | | 2012 | | 2011 | | 2012 | | 2011 | | 2012 | | 2011 |
| Entergy Corporation | | | | | | | | | | (Dollars in Thousands) | | | | | | | | | | (Dollars in Thousands) |
Utility: | | | | | | | | | | | | | | | | | | | | | | | | |
Preferred Stock or Preferred Membership Interests without sinking fund: | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Arkansas, 4.32%-6.45% Series | | 3,413,500 | | 3,413,500 | | 3,413,500 | | 3,413,500 | | $116,350 | | $116,350 | | 3,413,500 | | 3,413,500 | | 3,413,500 | | 3,413,500 | | $116,350 | | $116,350 |
Entergy Gulf States Louisiana, Series A 8.25 % | | | | | | | | | | 10,000 | | 10,000 | |
Entergy Gulf States Louisiana, Series A 8.25 % | | | 100,000 | | 100,000 | | 100,000 | | 100,000 | | 10,000 | | 10,000 |
Entergy Louisiana, 6.95% Series (a) | | 1,000,000 | | 1,000,000 | | 840,000 | | 840,000 | | 84,000 | | 84,000 | | 1,000,000 | | 1,000,000 | | 840,000 | | 840,000 | | 84,000 | | 84,000 |
Entergy Mississippi, 4.36%-6.25% Series | | 1,403,807 | | 1,403,807 | | 1,403,807 | | 1,403,807 | | 50,381 | | 50,381 | | 1,403,807 | | 1,403,807 | | 1,403,807 | | 1,403,807 | | 50,381 | | 50,381 |
Entergy New Orleans, 4.36%-5.56% Series | | 197,798 | | 197,798 | | 197,798 | �� | 197,798 | | 19,780 | | 19,780 | | 197,798 | | 197,798 | | 197,798 | | 197,798 | | 19,780 | | 19,780 |
| Total Utility Preferred Stock or Preferred Membership Interests without sinking fund | | 6,115,105 | | 6,115,105 | | 5,955,105 | | 5,955,105 | | 280,511 | | 280,511 | | 6,115,105 | | 6,115,105 | | 5,955,105 | | 5,955,105 | | 280,511 | | 280,511 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
Non-nuclear Wholesale Assets Business: | | | | | | | | | | | | | |
Entergy Wholesale Commodities: | | | | | | | | | | | | | |
Preferred Stock without sinking fund: | | | | | | | | | | | | | | | | | | | | | | | | |
Entergy Asset Management, 8.95% rate (b) | | 1,000,000 | | 1,000,000 | | 305,240 | | 297,376 | | 29,375 | | 29,738 | | 1,000,000 | | 1,000,000 | | - | | - | | - | | - |
Other | | - | | - | | - | | - | | 1,457 | | 780 | |
Total Subsidiaries' Preferred Stock without sinking fund | | 7,115,105 | | 7,115,105 | | 6,260,345 | | 6,252,481 | | $311,343 | | $311,029 | |
Total Subsidiaries’ Preferred Stock without sinking fund | | | 7,115,105 | | 7,115,105 | | 5,955,105 | | 5,955,105 | | $280,511 | | $280,511 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| (a) | In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders. |
| (b) | Upon the sale of Class B preferred shares in December 2009, Entergy Asset Management had issued and outstanding Class A and Class B preferred shares. The preferred stockholders' agreement provides that eachOn December 31 either20, 2011, Entergy Asset Management orpurchased all of the outstanding Class B preferred shareholders may request thatshares from the holder thereof; currently, there are no outstanding Class B preferred dividend rate be reset. Ifshares. On December 20, 2011, Entergy Asset Management andpurchased all of the preferred shareholders are unable to agree on a dividend reset rate, a preferred shareholder can request that its shares be sold to a third party. If Entergy Asset Management is unable to sell the preferred shares within 75 days, theoutstanding Class A preferred shareholders have the right to take control of theshares (278,905 shares) that were held by a third party; currently, there are 4,759 shares held by an Entergy Asset Management board of directors for the purpose of liquidating the assets of Entergy Asset Management in order to repay the preferred shares and any accrued dividends. Upon the sale of Class B shares resulting from a failed rate reset or a liquidation transaction by the Class A preferred shareholders, Class B shareholders have the option to exchange their shares for shares of Class A preferred stock.affiliate. |
All outstanding preferred stock and membership interests are cumulative.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
At December 31, 20092012 and 2008,2011, Entergy Gulf States Louisiana had outstanding 100,000 units of no par value 8.25% Series Preferred Membership Interests that were initially issued by Entergy Gulf States, Inc. as preference stock. The preference shares were converted into the preferred units as part of the jurisdictional separation. The distributions are cumulative and payable quarterly beginning March 15, 2008. The preferred membership interests are redeemable on or after December 15, 2015, at Entergy Gulf States Louisiana'sLouisiana’s option, at the fixed redemption price of $100 per unit.
The number of shares and units authorized and outstanding and dollar value of preferred stock and membership interests for Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31, 20092012 and 20082011 are presented below. All series of the Utility operating companies'companies’ preferred stock and membership interests are redeemable at the respective company'scompany’s option at the call prices presented. Dividends and distributions paid on all of Entergy'sEntergy’s preferred stock and membership interests series are eligible for the dividends received deduction. The dividends received deduction is limited by Internal Revenue Code section 244 for the following preferred stock series: Entergy Arkansas 4.72%, Entergy Mississippi 4.56%, and Entergy New Orleans 4.75%.
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price Per Share as of December 31, |
| | 2009 | | 2008 | | 2009 | | 2008 | | 2009 |
| Entergy Arkansas Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.32% Series | 70,000 | | 70,000 | | $7,000 | | $7,000 | | $103.65 |
4.72% Series | 93,500 | | 93,500 | | 9,350 | | 9,350 | | $107.00 |
4.56% Series | 75,000 | | 75,000 | | 7,500 | | 7,500 | | $102.83 |
4.56% 1965 Series | 75,000 | | 75,000 | | 7,500 | | 7,500 | | $102.50 |
6.08% Series | 100,000 | | 100,000 | | 10,000 | | 10,000 | | $102.83 |
Cumulative, $25 par value: | | | | | | | | | |
6.45% Series (a) | 3,000,000 | | 3,000,000 | | 75,000 | | 75,000 | | $- |
Total without sinking fund | 3,413,500 | | 3,413,500 | | $116,350 | | $116,350 | | |
| |
Shares/Units
Authorized and Outstanding | |
Dollars
(In Thousands) | | Call Price Per Share/Unit as of December 31, |
| | 2009 | | 2008 | | 2009 | | 2008 | | 2009 |
Entergy Gulf States Louisiana Preferred Membership Interests | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 liquidation value: | | | | | | | | | |
8.25% Series (b) | 100,000 | | 100,000 | | $10,000 | | $10,000 | | $- |
Total without sinking fund | 100,000 | | 100,000 | | $10,000 | | $10,000 | | |
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price per Share as of December 31, |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 |
| Entergy Arkansas Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.32% Series | 70,000 | | 70,000 | | $7,000 | | $7,000 | | $103.65 |
4.72% Series | 93,500 | | 93,500 | | 9,350 | | 9,350 | | $107.00 |
4.56% Series | 75,000 | | 75,000 | | 7,500 | | 7,500 | | $102.83 |
4.56% 1965 Series | 75,000 | | 75,000 | | 7,500 | | 7,500 | | $102.50 |
6.08% Series | 100,000 | | 100,000 | | 10,000 | | 10,000 | | $102.83 |
Cumulative, $25 par value: | | | | | | | | | |
6.45% Series (a) | 3,000,000 | | 3,000,000 | | 75,000 | | 75,000 | | $25 |
Total without sinking fund | 3,413,500 | | 3,413,500 | | $116,350 | | $116,350 | | |
| | Units Authorized and Outstanding | | Dollars (In Thousands) | | Call Price Per Unit as of December 31, | Units Authorized and Outstanding | | Dollars (In Thousands) | | Call Price per Unit as of December 31, |
| | 2009 | | 2008 | | 2009 | | 2008 | | 2009 | 2012 | | 2011 | | 2012 | | 2011 | | 2012 |
| Entergy Louisiana Preferred Membership Interests | | | | | | | | | | |
Entergy Gulf States Louisiana Preferred Membership Interests | | | | | | | | | | |
Without sinking fund: | | | | | | | | | | | | | | | | | | |
Cumulative, $100 liquidation value: | | | | | | | | | | | | | | | | | | |
6.95% Series (c) | 1,000,000 | | 1,000,000 | | $100,000 | | $100,000 | | $- | |
8.25% Series (b) | | 100,000 | | 100,000 | | $10,000 | | $10,000 | | $- |
Total without sinking fund | 1,000,000 | | 1,000,000 | | $100,000 | | $100,000 | | | 100,000 | | 100,000 | | $10,000 | | $10,000 | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | Units Authorized and Outstanding | | Dollars (In Thousands) | | Call Price per Unit as of December 31, |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 |
| Entergy Louisiana Preferred Membership Interests | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 liquidation value: | | | | | | | | | |
6.95% Series (a) | 1,000,000 | | 1,000,000 | | $100,000 | | $100,000 | | $100 |
Total without sinking fund | 1,000,000 | | 1,000,000 | | $100,000 | | $100,000 | | |
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price per Share as of December 31, |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 |
| Entergy Mississippi Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.36% Series | 59,920 | | 59,920 | | $5,992 | | $5,992 | | $103.88 |
4.56% Series | 43,887 | | 43,887 | | 4,389 | | 4,389 | | $107.00 |
4.92% Series | 100,000 | | 100,000 | | 10,000 | | 10,000 | | $102.88 |
Cumulative, $25 par value | | | | | | | | | |
6.25% Series (a) | 1,200,000 | | 1,200,000 | | 30,000 | | 30,000 | | $25 |
Total without sinking fund | 1,403,807 | | 1,403,807 | | $50,381 | | $50,381 | | |
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price per Share as of December 31, |
| | 2012 | | 2011 | | 2012 | | 2011 | | 2012 |
| Entergy New Orleans Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.36% Series | 60,000 | | 60,000 | | $6,000 | | $6,000 | | $104.58 |
4.75% Series | 77,798 | | 77,798 | | 7,780 | | 7,780 | | $105.00 |
5.56% Series | 60,000 | | 60,000 | | 6,000 | | 6,000 | | $102.59 |
Total without sinking fund | 197,798 | | 197,798 | | $19,780 | | $19,780 | | |
| (a) | Series is callable at par. |
| (b) | Series is callable at par on and after December 15, 2015. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price Per Share as of December 31, |
| | 2009 | | 2008 | | 2009 | | 2008 | | 2009 |
| Entergy Mississippi Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.36% Series | 59,920 | | 59,920 | | $5,992 | | $5,992 | | $103.88 |
4.56% Series | 43,887 | | 43,887 | | 4,389 | | 4,389 | | $107.00 |
4.92% Series | 100,000 | | 100,000 | | 10,000 | | 10,000 | | $102.88 |
Cumulative, $25 par value | | | | | | | | | |
6.25% Series (d) | 1,200,000 | | 1,200,000 | | 30,000 | | 30,000 | | $- |
Total without sinking fund | 1,403,807 | | 1,403,807 | | $50,381 | | $50,381 | | |
| | Shares Authorized and Outstanding | | Dollars (In Thousands) | | Call Price Per Share as of December 31, |
| | 2009 | | 2008 | | 2009 | | 2008 | | 2009 |
| Entergy New Orleans Preferred Stock | | | | | | | | | |
Without sinking fund: | | | | | | | | | |
Cumulative, $100 par value: | | | | | | | | | |
4.36% Series | 60,000 | | 60,000 | | $6,000 | | $6,000 | | $104.58 |
4.75% Series | 77,798 | | 77,798 | | 7,780 | | 7,780 | | $105.00 |
5.56% Series | 60,000 | | 60,000 | | 6,000 | | 6,000 | | $102.59 |
Total without sinking fund | 197,798 | | 197,798 | | $19,780 | | $19,780 | | |
(a) | Series is non-callable until April 2011; thereafter callable at par. |
(b) | Series is non-callable until January 2016; thereafter callable at par. |
(c) | Series is non-callable until December 2010; thereafter callable at par. |
(d) | Series is non-callable until August 2010; thereafter callable at par. |
In connection with the adoption of the new accounting pronouncement regarding non-controlling interests Entergy evaluated the accounting standards regarding the classification and measurement of redeemable securities. These standards require the classification of securities between liabilities and shareholders' equity on the balance sheet if the holders of those securities have protective rights that allow them to gain control of the board of directors in certain circumstances. These rights would have the effect of giving the holders the ability to potentially redeem their securities, even if the likelihood of occurrence of these circumstances is considered remote. The Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans articles of incorporation provide, generally, that the holders of each company's preferred securities may elect a majority of the respective company's board of directors if dividends are not paid for a year, until such time as the dividends in arrears are paid. Therefore, Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans present their preferred securities outstanding between liabilities and shareholders' equity on the balance sheet as of December 31, 2009, and are restating the December 31, 2008 amounts presented in each affected company's financial statements to reflect this same presentation, which reduces the previously reported total shareholders' equity amount by $116 million, $50 million and $20 million for Entergy Arkansas, Entergy Mississippi and Entergy New Orleans, respectively. The 2007 shareholders' equity for each of the affected companies is restated by the same respective amount. This change has no net effect on those companies' reported amount of total liabilities and equity or any other financial statements presented or amounts included therein.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Common Stock
Treasury Stock
TreasuryCommon stock and treasury stock shares activity for Entergy for 2009, 2008,2012, 2011, and 20072010 is as follows:
| | | 2009 | | 2008 | | 2007 | |
| | | Treasury | | | | Treasury | | | | Treasury | | | |
| | | Shares | | Cost | | Shares | | Cost | | Shares | | Cost | | 2012 | | 2011 | | 2010 |
| | | | | (In Thousands) | | | | (In Thousands) | | | | (In Thousands) | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Beginning Balance, January 1 | | 58,815,518 | | $4,175,214 | | 55,053,847 | | $3,734,865 | | 45,506,311 | | $2,644,390 | | 254,752,788 | | 78,396,988 | | 254,752,788 | | 76,006,920 | | 254,752,788 | | 65,634,580 |
Repurchases | | 7,680,000 | | 613,125 | | 4,792,299 | | 512,351 | | 11,581,842 | | 1,215,578 | | - | | - | | - | | 3,475,000 | | - | | 11,490,551 |
Issuances: | | | | | | | | | | | | | | | | | | | | | | | | |
Employee Stock-Based Compensation Plans | | (856,390) | | (60,846) | | (1,025,408) | | (71,636) | | (2,029,686) | | (124,801) | | - | | (1,446,305) | | - | | (1,079,008) | | - | | (1,113,411) |
Directors' Plan | | (4,548) | | (326) | | (5,220) | | (366) | | (4,620) | | (302) | |
Directors’ Plan | | | - | | (5,444) | | - | | (5,924) | | - | | (4,800) |
| Ending Balance, December 31 | | 65,634,580 | | $4,727,167 | | 58,815,518 | | $4,175,214 | | 55,053,847 | | $3,734,865 | | 254,752,788 | | 76,945,239 | | 254,752,788 | | 78,396,988 | | 254,752,788 | | 76,006,920 |
Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors'(Directors’ Plan), two Equity Ownership Plans of Entergy Corporation and Subsidiaries, the Equity Awards Plan of Entergy Corporation and Subsidiaries, and certain other stock benefit plans. The Directors'Directors’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed number of shares of Entergy Corporation common stock.
In January 2007, the Board approved a repurchase program under which Entergy is authorized to repurchase up to $1.5 billion of its common stock. In January 2008, the Board authorized an incremental $500 million share repurchase program to enable Entergy to consider opportunistic purchases in response to equity market conditions. Entergy completed both the $1.5 billion and $500 million programs in the third quarter 2009. In October 2009 the Board granted authority for an additionala $750 million share repurchase program which was completed in the fourth quarter 2010. In October 2010 the Board granted authority for an additional $500 million share repurchase program. As of December 31, 2012, $350 million of authority remains under the $500 million share repurchase program.
Retained Earnings and Dividend Restrictions
Provisions within the articles of incorporation or pertinent indentures and various other agreements relating to the long-term debt and preferred stock of certain of Entergy Corporation'sCorporation’s subsidiaries could restrict the payment of cash dividends or other distributions on their common and preferred stock.equity. As of December 31, 2009,2012, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $461.6$394.9 million and $236$68.5 million, respectively. Entergy Corporation received dividend payments from subsidiaries totaling $417$439 million in 2009, $3132012, $595 million in 2008,2011, and $625$580 million in 2007.2010.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Comprehensive Income
Accumulated other comprehensive income (loss) is included in the equity section of the balance sheets of Entergy, Entergy Gulf States Louisiana, and Entergy Louisiana. Accumulated other comprehensive income (loss) in the balance sheets included the following components:
| | | Entergy | | Entergy Gulf States Louisiana | | Entergy Louisiana |
| | | December 31, 2012 | | December 31, 2011 | | December 31, 2012 | | December 31, 2011 | | December 31, 2012 | | December 31, 2011 |
| | | (In Thousands) |
| | | | | | | | | | | | | |
Cash flow hedges net unrealized gain | | $79,905 | | $177,497 | | $- | | $- | | $- | | $- |
Pension and other postretirement liabilities | | (590,712) | | (499,556) | | (65,229) | | (69,610) | | (46,132) | | (39,507) |
Net unrealized investment gains | | 214,547 | | 150,939 | | - | | - | | - | | - |
| Foreign currency translation | | 3,177 | | 2,668 | | - | | - | | - | | - |
| Total | | ($293,083) | | ($168,452) | | ($65,229) | | ($69,610) | | ($46,132) | | ($39,507) |
Other comprehensive income and total comprehensive income for years ended December 31, 2012, 2011, and 2010 are presented in Entergy’s, Entergy Gulf States Louisiana’s, and Entergy Louisiana’s Statements of Comprehensive Income.
NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy and the Registrant Subsidiaries are involved in a number of legal, regulatory, and tax proceedings before various courts, regulatory commissions, and governmental agencies in the ordinary course of business. While management is unable to predict the outcome of such proceedings, management does not believe that the ultimate resolution of these matters will have a material adverse effect on Entergy'sEntergy’s results of operations, cash flows, or financial condition. Entergy discusses regulatory proceedings in Note 2 to the financial statements and discusses tax proceedings in Note 3 to the financial statements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Vidalia Purchased Power Agreement
Entergy Louisiana has an agreement extending through the year 2031 to purchase energy generated by a hydroelectric facility known as the Vidalia project. Entergy Louisiana made payments under the contract of approximately $215.6$125.0 million in 2009, $167.72012, $185.6 million in 2008,2011, and $130.8$216.5 million in 2007.2010. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $169.8$174.9 million in 2010,2013, and a total of $2.81$2.37 billion for the years 20112014 through 2031. Entergy Louisiana currently recovers the costs of the purchased energy through its fuel adjustment clause.
In an LPSC-approved settlement related to tax benefits from the tax treatment of the Vidalia contract, Entergy Louisiana agreed to credit rates by $11 million each year for up to ten years, beginning in October 2002. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.8$11.3 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. As discussed in more detail in Note 3 to the financial statements, in August
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011, Entergy agreed to a settlement with the IRS regarding the mark-to-market income tax treatment of various wholesale electric power purchase and sale agreements, including the Vidalia agreement. In October 2011 the LPSC approved a final settlement under which Entergy Louisiana agreed to share the remaining benefits of this tax accounting election by crediting customers an additional $20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a $199 million regulatory charge and a corresponding net-of-tax regulatory liability to reflect this obligation. The provisions of the settlement also provide that the LPSC shall not recognize or use Entergy Louisiana'sLouisiana’s use of the cash benefits from the tax treatment in setting any of Entergy Louisiana'sLouisiana’s rates. Therefore, to the extent Entergy Louisiana'sLouisiana’s use of the proceeds would ordinarily have reduced its rate base, no change in rate base shall be reflected for ratemaking purposes.
Nuclear Insurance
Third Party Liability Insurance
The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act requires nuclear power plants to show evidence of financial protection in the event of a nuclear accident. This protection must consist of two layers of coverage:
| 1. | The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $375 million. If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. |
| 2. | Within the Secondary Financial Protection level, each nuclear reactor has a contingent obligation to pay a retrospective premium, equal to its proportionate share of the loss in excess of the primary level, regardless of proximity to the incident or fault, up to a maximum of $117.5 million per reactor per incident (Entergy's(Entergy’s maximum total contingent obligation per incident is $1.3 billion). This consists of a $111.9 million maximum retrospective premium plus a five percent surcharge, which equates to $117.5 million, that may be payable, if needed, at a rate that is currently set at $17.5 million per year per incident per nuclear power reactor. A $300 million industry-wide aggregate limit exists |
| 3. | In the event that one or more acts of terrorism cause a nuclear power plant accident, which results in third-party damages – off-site property and environmental damage, off-site bodily injury, and on-site third-party bodily injury (i.e. contractors); the primary level provided by ANI combined with the Secondary Financial Protection would provide $12.6 billion in coverage. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for domestically-sponsoredup to $100 billion in coverage in excess of existing coverage for a terrorist acts. ��There is no aggregate limitation for foreign-sponsored terrorist acts.event. |
Currently, 104 nuclear reactors are participating in the Secondary Financial Protection program. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactors provides over $12.2 billion in secondary layer insurance coverage to compensate the public in the event of a nuclear power reactor accident. The Price-Anderson Act provides that all potential liability for a nuclear accident is limited to the amounts of insurance coverage available under the primary and secondary layers.
Entergy Arkansas has two licensed reactors and Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). Entergy's Non-Utility Nuclear business ownsThe Entergy Wholesale Commodities segment includes the ownership and operatesoperation of six nuclear power reactors and ownsthe ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Property Insurance
Entergy'sEntergy’s nuclear owner/licensee subsidiaries are members of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members'members’ nuclear generating plants. Effective April 1, 2009,2012, Entergy was insured against such losses per the following structures:
Utility Plants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3)
| · | Primary Layer (per plant) - $500 million per occurrence |
| · | Excess Layer (per plant) - $750 million per occurrence |
| · | Blanket Layer (shared among the Utility plants) - $350 million per occurrence |
| · | Total limit - $1.6 billion per occurrence |
| · | $2.5 million per occurrence - Turbine/generator damage |
| · | $2.5 million per occurrence - Other than turbine/generator damage |
| · | $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption |
Note: ANO 1 and 2 share in the primary and excess layers with common policies because the policies are issued on a per site basis.
Non-Utility NuclearEntergy Wholesale Commodities Plants (Indian Point, 2 and 3, FitzPatrick, Pilgrim, Vermont Yankee, Palisades, and Big Rock Point)
| · | Primary Layer (per plant) - $500 million per occurrence |
| · | Excess Layer - $615 million per occurrence |
| · | Total limit - $1.115 billion per occurrence |
| · | $2.5 million per occurrence - Turbine/generator damage |
| · | $2.5 million per occurrence - Other than turbine/generator damage |
| · | $10 million per occurrence plus 10% of amount above $10 million - Damage from a windstorm, flood, earthquake, or volcanic eruption |
Note: The Indian Point 2 and 3Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. Big Rock Point has its own primary policy with no excess coverage.
In addition, Waterford 3, Grand Gulf, and the Non-Utility NuclearEntergy Wholesale Commodities plants are also covered under NEIL'sNEIL’s Accidental Outage Coverage program. This coverage provides certain fixed indemnities in the event of an unplanned outage that results from a covered NEIL property damage loss, subject to a deductible and a waiting period. The following summarizes this coverage effective April 1, 2009:2012:
Waterford 3
| · | $2.95 million weekly indemnity |
| · | $413 million maximum indemnity |
| · | Deductible: 26 week waitingdeductible period |
Grand Gulf
| · | $400,000 weekly indemnity (total for four policies) |
| · | $56 million maximum indemnity (total for four policies) |
| · | Deductible: 26 week waitingdeductible period |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Indian Point 2, Indian Point 3, and Palisades
| · | $4.5 million weekly indemnity |
| · | $490 million maximum indemnity |
| · | Deductible: 12 week waitingdeductible period |
FitzPatrick and Pilgrim
| · | $4.0 million weekly indemnity |
| · | $490 million maximum indemnity |
| · | Deductible: 12 week waitingdeductible period |
Vermont Yankee
| · | $3.5 million weekly indemnity |
| · | $435 million maximum indemnity |
| · | Deductible: 12 week waitingdeductible period |
Under the property damage and accidental outage insurance programs, all NEIL insured plants could be subject to assessments should losses exceed the accumulated funds available from NEIL. Effective April 1, 2009,2012, the maximum amounts of such possible assessments per occurrence were as follows:
| | | Assessments |
| | | (In Millions) |
| Utility: | | |
| Entergy Arkansas | | $21.321.9 |
| Entergy Gulf States Louisiana | | $17.118.9 |
| Entergy Louisiana | | $19.022.0 |
| Entergy Mississippi | | $0.07 |
| Entergy New Orleans | | $0.07 |
| Entergy Texas | | N/A |
| System Energy | | $15.118.4 |
| | | |
Non-Utility NuclearEntergy Wholesale Commodities | | $- |
Effective April 1, 2009, potentialPotential assessments for the Non-Utility NuclearEntergy Wholesale Commodities plants are covered by insurance obtained through NEIL'sNEIL’s reinsurers.
Entergy maintains property insurance for its nuclear units in excess of the NRC'sNRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance must be used, first, to render the reactor safe and stable, and second, to complete decontamination operations. Only after proceeds are dedicated for such use and regulatory approval is secured would any remaining proceeds be made available for the benefit of plant owners or their creditors.
In the event that one or more acts of terrorism causes property damage under one or more or all nuclear insurance policies issued by NEIL (including, but not limited to, those described above) within 12 months from the date the first property damage occurs, the maximum recovery under all such nuclear insurance policies shall be an aggregate of $3.24 billion plus the additional amounts recovered for such losses from reinsurance, indemnity, and any other sources applicable to such losses. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Conventional Property Insurance
Entergy'sEntergy’s conventional property insurance program provides coverage of up to $400 million on an Entergy system-wide basis for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an "each“each and every loss"loss” basis; up to $400 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, flood, ice storm, and tornado)flood) on an annual aggregate basis; and up to $125 million for certain other natural perils (direct physical loss or damage due to a named windstorm orand associated storm surge) on an annual aggregate basis; and up to $400 million in coverage for all other natural perils not previously stated (direct physical loss or damage due to a tornado, ice storm, or any other natural peril except named windstorm and associated storm surge, earthquake, tsunami, and flood) on an “each and every loss” basis. The conventional property insurance program only provides up to $50 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis. This $50 million limit is subject to: the $400 million annual aggregate basis.limit for the natural perils of earthquake, tsunami, and flood; the $125 million annual aggregate limit for the natural perils of named windstorm and associated storm surge; the $400 million per occurrence limit for all other natural perils not previously stated, which includes tornado and ice storm, but excludes named windstorm and associated storm surge, earthquake, tsunami, and flood; and the $400 million per occurrence limit for operational perils. The coverage is subject to a $40 million self-insured retention per occurrence for the natural perils of named windstorm and associated storm surge, earthquake, flood, and tsunami; and a $20 million self-insured retention per occurrence for operational perils and a $35 million self-insured retention per occurrence forall other natural perils not previously stated, which includes tornado and for the Entergy New Orleans gas distribution system.ice storm, but excludes named windstorm and associated storm surge, earthquake, tsunami, and flood.
Covered property generally includes power plants, substations over $5 million in value, facilities, inventories, and gas distribution-related properties. Excluded property generally includes above-ground transmission and distribution lines, poles, and towers. The primary layer consists of a $125 million layer in excess of the self-insured retention and the excess layer consists of a $275 million layer in excess of the $125 million primary layer. Both layers are placed on a quota share basis through several insurers. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries, including the owners of the Non-Utility Nuclearnuclear power plants.plants in the Entergy Wholesale Commodities segment. Entergy also purchases $300 million in terrorism insurance coverage for its conventional property. The Terrorism Risk Insurance Reauthorization Act of 2007 created a government program that provides for up to $100 billion in coverage in excess of existing coverage for a terrorist event.
In addition to the conventional property insurance program, Entergy has purchased additional coverage ($20 million per occurrence) for some of its non-regulated, non-generation assets. This policy serves to buy-down the $20 million deductible and is placed on a scheduled location basis. The applicable deductibles are $100,000 to $250,000, except for properties that are damaged by flooding and properties whose values are greater than $20 million; these properties have a $500,000 deductible. Four nuclear locations have a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each respective nuclear site.
Gas System Rebuild Insurance Proceeds (Entergy New Orleans)
Entergy New Orleans received insurance proceeds for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans'Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as "Gas“Gas system rebuild insurance proceeds"proceeds” on Entergy New Orleans'Orleans’s balance sheet.
Waterford 3 Lease Obligations(Entergy Louisiana)
In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million. The interests represent approximately 9.3% of Waterford 3. Upon the occurrence of certain events, Entergy Louisiana may be obligated to pay amounts sufficient to permit the termination of the lease transactions and may be required to assume the outstanding bonds issued to finance, in part, the lessors' acquisition of the undivided interests in Waterford 3.
Employment and Labor-related Proceedings
The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees, recognized bargaining representatives, and third parties not selected for open positions.positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries. Generally, the amount of damages being sought is not specified in these proceedings. These actions
Entergy Corporation and Subsidiaries
Notes to Financial Statements
include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board;Board or concerning the National Labor Relations Act; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsoredCorporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these suitslawsuits and proceedings and deny liability to the claimants. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of Entergy or the Utility operating companies.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 500400 lawsuits involving approximately 5,000 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position, results of operation, or cash flows of the Utility operating companies.
Grand Gulf - Related Agreements
Capital Funds Agreement (System(Entergy Corporation and System Energy)
System Energy has entered into agreements with Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans whereby they are obligated to purchase their respective entitlements of capacity and energy from System Energy's current 90%Energy’s interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy'sEnergy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation'sCorporation’s obligations under the Capital Funds Agreement, to cover any shortfalls from payments received from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under these agreements.
Unit Power Sales Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
System Energy has agreed to sell all of its current 90% share of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans in accordance with specified percentages (Entergy Arkansas-36%, Entergy Louisiana-14%, Entergy Mississippi-33%, and Entergy New Orleans-17%) as ordered by the FERC. Charges under this agreement are paid in consideration for the purchasing companies'companies’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy delivered so long as the unit remains in commercial operation.delivered. The agreement will remain in effect until terminated by the parties and the termination is approved by the FERC, most likely upon Grand Gulf'sGulf’s retirement from service. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 20092012 under the agreement are approximately $17$19.0 million for Entergy Arkansas, $6.8$7.6 million for Entergy Louisiana, $14$16.1 million for Entergy Mississippi, and $8.3$9.2 million for Entergy New Orleans.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Availability Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans are individually obligated to make payments or subordinated advances to System Energy in accordance with stated percentages (Entergy Arkansas-17.1%, Entergy Louisiana-26.9%, Entergy Mississippi-31.3%, and Entergy New Orleans-24.7%) in amounts that, when added to amounts received under the Unit Power Sales Agreement or otherwise, are adequate to cover all of System Energy'sEnergy’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years.years (See Reallocation Agreement terms below.)below) and expenses incurred in connection with a permanent shutdown of Grand Gulf. System Energy has assigned its rights to payments and advances to certain creditors as security for certain obligations. Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement have exceeded the amounts payable under the Availability Agreement. Accordingly, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments.
Reallocation Agreement (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and System Energy)
System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans entered into the Reallocation Agreement relating to the sale of capacity and energy from Grand Gulf and the related costs, in which Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans agreed to assume all of Entergy Arkansas'Arkansas’s responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC'sFERC’s decision allocating a portion of Grand Gulf capacity and energy to Entergy Arkansas supersedes the Reallocation Agreement as it relates to Grand Gulf. Responsibility for any Grand Gulf 2 amortization amounts has been individually allocated (Entergy Louisiana-26.23%, Entergy Mississippi-43.97%, and Entergy New Orleans-29.80%) under the terms of the Reallocation Agreement. However, the Reallocation Agreement does not affect Entergy Arkansas'Arkansas’s obligation to System Energy'sEnergy’s lenders under the assignments referred to in the preceding paragraph. Entergy Arkansas would be liable for its share of such amounts if Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans were unable to meet their contractual obligations. No payments of any amortization amounts will be required so long as amounts paid to System Energy under the Unit Power Sales Agreement, including other funds available to System Energy, exceed amounts required under the Availability Agreement, which is expected to be the case for the foreseeable future.
Reimbursement Agreement (System Energy)
In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The interests represent approximately 11.5% of Grand Gulf. During the term of the leases, System Energy is required to maintain letters of credit for the equity investors to secure certain amounts payable to the equity investors under the transactions.
Under the provisions of the reimbursement agreement relating to the letters of credit, System Energy has agreed to a number of covenants regarding the maintenance of certain capitalization and fixed charge coverage ratios. System Energy agreed, during the term of the reimbursement agreement, to maintain a ratio of debt to total liabilities and equity less than or equal to 70%. In addition, System Energy must maintain, with respect to each fiscal quarter during the term of the reimbursement agreement, a ratio of adjusted net income to interest expense of at least 1.50 times earnings. As of December 31, 2009,2012, System Energy was in compliance with these covenants.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Accounting standards require the recording of liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of those assets. For Entergy, substantially all of its asset retirement obligations consist of its liability for decommissioning its nuclear power plants. In addition, an insignificant amount of removal costs associated with non-nuclear power plants is also included in the decommissioning line item on the balance sheets.
These liabilities are recorded at their fair values (which are the present values of the estimated future cash outflows) in the period in which they are incurred, with an accompanying addition to the recorded cost of the long-lived asset. The asset retirement obligation is accreted each year through a charge to expense, to reflect the time value of money for this present value obligation. The accretion will continue through the completion of the asset retirement activity. The amounts added to the carrying amounts of the long-lived assets will be depreciated over the useful lives of the assets. The application of accounting standards related to asset retirement obligations is earnings neutral to the rate-regulated business of the Registrant Subsidiaries.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In accordance with ratemaking treatment and as required by regulatory accounting standards, the depreciation provisions for the Registrant Subsidiaries include a component for removal costs that are not asset retirement obligations under accounting standards. In accordance with regulatory accounting principles, the Registrant Subsidiaries have recorded regulatory assets (liabilities) in the following amounts to reflect their estimates of the difference between estimated incurred removal costs and estimated removal costs recovered in rates:
| | | December 31, | | December 31, |
| | | 2009 | | 2008 | | 2012 | | 2011 |
| | | (In Millions) | | (In Millions) |
| | | | | | | | | |
| Entergy Arkansas | | ($7.3) | | $5.9 | | ($12.2) | | ($16.4) |
| Entergy Gulf States Louisiana | | ($7.5) | | ($3.6) | | ($22.0) | | ($30.3) |
| Entergy Louisiana | | ($21.7) | | ($43.5) | | ($9.2) | | ($62.6) |
| Entergy Mississippi | | $44.5 | | $40.0 | | $57.4 | | $48.5 |
| Entergy New Orleans | | $15.2 | | $15.4 | | $29.9 | | $16.3 |
| Entergy Texas | | $7.2 | | $34.7 | | $11.5 | | $4.5 |
| System Energy | | $13.9 | | $14.5 | | $56.8 | | $11.8 |
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 20092012 by Entergy were as follows:
| | Liabilities as of December 31, 2008 | | Accretion | | Change in Cash Flow Estimate | | | Spending | | Liabilities as of December 31, 2009 | Liabilities as of December 31, 2011 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2012 |
| | | | | | (In Millions) | | | | | | | | | | (In Millions) | | | | |
| Utility: | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | $540.7 | | $34.6 | | ($8.9) | | | $- | | $566.4 | $640.2 | | $40.5 | | $- | | $- | | $680.7 |
| Entergy Gulf States Louisiana | $222.9 | | $19.6 | | $78.7 | | | $- | | $321.2 | $359.8 | | $21.0 | | $- | | $- | | $380.8 |
| Entergy Louisiana | $276.8 | | $21.4 | | $- | | | $- | | $298.2 | $345.8 | | $23.4 | | $48.9 | | $- | | $418.1 |
| Entergy Mississippi | $4.8 | | $0.3 | | $- | | | $- | | $5.1 | $5.7 | | $0.3 | | $- | | $- | | $6.0 |
| Entergy New Orleans | $3.0 | | $0.2 | | $- | | | $- | | $3.2 | $2.9 | | $0.2 | | $- | | ($0.9) | | $2.2 |
| Entergy Texas | $3.3 | | $0.1 | | $- | | | $- | | $3.4 | $3.9 | | $0.2 | | $- | | $- | | $4.1 |
| System Energy | $396.2 | | $29.4 | | ($4.2) | | | $- | | $421.4 | $445.4 | | $33.0 | | $- | | $- | | $478.4 |
| | | | | | | | | | | | | | | | | | | | |
| Non-Utility Nuclear | $1,228.7 | | $99.3 | | $- | | | ($8.5) | | $1,319.5 | |
| | | | | | | | | | | | |
| Other | $1.2 | | $- | | $- | | | ($0.1) | | $1.1 | |
| Entergy Wholesale Commodities | | $1,492.9 | | $119.4 | | ($58.5) | | ($10.5) | | $1,543.3 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 20082011 by Entergy were as follows:
| | Liabilities as of December 31, 2007 | | Accretion | | Change in Cash Flow Estimate | | | Spending | | Liabilities as of December 31, 2008 | Liabilities as of December 31, 2010 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2011 |
| | | | | | (In Millions) | | | | | | | | | | (In Millions) | | | | |
| Utility: | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | $505.6 | | $35.1 | | $- | | | $- | | $540.7 | $602.2 | | $38.0 | | $- | | $- | | $640.2 |
| Entergy Gulf States Louisiana | $204.8 | | $18.1 | | $- | | | $- | | $222.9 | $339.9 | | $19.9 | | $- | | $- | | $359.8 |
| Entergy Louisiana | $257.1 | | $19.9 | | ($0.2) | | | $- | | $276.8 | $321.2 | | $24.6 | | $- | | $- | | $345.8 |
| Entergy Mississippi | $4.5 | | $0.3 | | $- | | | $- | | $4.8 | $5.4 | | $0.3 | | $- | | $- | | $5.7 |
| Entergy New Orleans | $2.8 | | $0.2 | | $- | | | $- | | $3.0 | $3.4 | | $0.2 | | $- | | ($0.7) | | $2.9 |
| Entergy Texas | $3.1 | | $0.2 | | $- | | | $- | | $3.3 | $3.6 | | $0.3 | | $- | | $- | | $3.9 |
| System Energy | $368.6 | | $27.6 | | $- | | | $- | | $396.2 | $452.8 | | $31.5 | | ($38.9) | | $- | | $445.4 |
| | | | | | | | | | | | | | | | | | | | |
| Non-Utility Nuclear | $1,141.6 | | $93.5 | | $13.7 | | | ($20.1) | | $1,228.7 | |
| | | | | | | | | | | | |
| Other | $1.1 | | $0.1 | | $- | | | $- | | $1.2 | |
| Entergy Wholesale Commodities | | $1,420.0 | | $115.6 | | ($34.1) | | ($8.6) | | $1,492.9 |
Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 20082012 and 20092011 Entergy updated decommissioning cost estimates for certain nuclear power plants.
In the firstsecond quarter 2009,2012, Entergy ArkansasLouisiana recorded a revision to its estimated decommissioning cost liabilitiesliability for ANO 1 and 2Waterford 3 as a result of a revised decommissioning cost study. The revised estimatesestimate resulted in an $8.9a $48.9 million reductionincrease in its decommissioning cost liability, along with a corresponding reductionincrease in the related regulatory asset.asset retirement costs asset that will be depreciated over the remaining life of the unit.
In the second quarter 2009,2012, Entergy Wholesale Commodities recorded a reduction of $60.6 million in the estimated decommissioning cost liability for a plant as a result of a revised decommissioning cost study. The revised estimate resulted in a credit to decommissioning expense of $49 million, reflecting the excess of the reduction in the liability over the amount of the undepreciated asset retirement costs asset.
In the first quarter of 2011, System Energy recorded a revision to its estimated decommissioning cost liabilitiesliability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $4.2$38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
In the fourth quarter 2009,of 2011, Entergy Gulf States LouisianaWholesale Commodities recorded a revision to its estimatedreduction of $34.1 million in the decommissioning cost liabilitiesliability for River Benda plant as a result of a revised decommissioning cost study.study obtained to comply with a state regulatory requirement. The revised estimatecost study resulted in a $78.7 million increase in its decommissioning liability, along with a corresponding increasechange in the related asset retirement obligation asset that will be depreciatedundiscounted cash flows and a credit to decommissioning expense of $34.1 million, reflecting the excess of the reduction in the liability over the remaining lifeamount of the units.
In the third quarter 2008, Entergy's Non-Utility Nuclear business recorded an increase of $13.7 million in decommissioning liabilities for certain of its plants as a result of revised decommissioning cost studies. The revised estimates resulted in the recognition of a $13.7 million asset retirement obligation asset that will be depreciated over the remaining life of the units.undepreciated assets.
For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability.liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the rightrights to require the Entergy subsidiaries to assume each of the decommissioning liabilityliabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy.the Entergy subsidiaries. If the decommissioning liability isliabilities are retained by NYPA, the Entergy subsidiaries will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. Entergy recorded an asset, representing its estimatewhich is now $546.5 million as of the present value of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
December 31, 2012, representing its estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costcosts estimated in an independent decommissioning cost study.studies. The asset is increased by monthly accretion based on the applicable discount rate necessary to ultimately provide for the estimated future value of the decommissioning contract. The monthly accretion is recorded as interest income.
Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 2012 are as follows:
| | | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) |
| | | (In Millions) |
| | | | | |
| Utility: | | | | |
| ANO 1 and ANO 2 | | $600.6 | | $204.0 |
| River Bend | | $477.4 | | ($1.7) |
| Waterford 3 | | $287.4 | | $126.7 |
| Grand Gulf | | $490.6 | | $58.9 |
| Entergy Wholesale Commodities | | $2,334.1 | | $- |
Entergy maintains decommissioning trust funds that are committed to meeting the costs of decommissioning the nuclear power plants. The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets of Entergy as of December 31, 20092011 are as follows:
| | Decommissioning Trust Fair Values | | Regulatory Asset | | Decommissioning Trust Fair Values | | Regulatory Asset |
| | (In Millions) | | (In Millions) |
| | | | | | | | |
| Utility: | | | | | | | |
| ANO 1 and ANO 2 | $440.2 | | $173.7 | | $541.7 | | $181.5 |
| River Bend | $349.5 | | $11.0 | | $420.9 | | $5.5 |
| Waterford 3 | $209.1 | | $91.0 | | $254.0 | | $116.1 |
| Grand Gulf | $327.0 | | $97.8 | | $423.4 | | $59.6 |
| Non-Utility Nuclear | $1,885.4 | | $- | |
| Entergy Wholesale Commodities | | | $2,148.0 | | $- |
The fair values of the decommissioning trust funds and the related asset retirement obligation regulatory assets of Entergy as of December 31, 2008 are as follows:
| | Decommissioning Trust Fair Values | | Regulatory Asset |
| | (In Millions) |
| | | | |
| Utility: | | | |
| ANO 1 and ANO 2 | $390.5 | | $159.5 |
| River Bend | $303.2 | | $8.7 |
| Waterford 3 | $180.9 | | $77.7 |
| Grand Gulf | $268.8 | | $96.1 |
| Non-Utility Nuclear | $1,688.9 | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
General
As of December 31, 2009,2012, Entergy Corporation and subsidiaries had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) with minimum lease payments as follows:
Year | | Operating Leases | | Capital Leases |
| | | (In Thousands) |
| | | | | |
| 2010 | | $95,392 | | $4,924 |
| 2011 | | 79,043 | | 4,924 |
| 2012 | | 66,042 | | 4,924 |
| 2013 | | 58,279 | | 4,924 |
| 2014 | | 58,557 | | 3,124 |
| Years thereafter | | 172,752 | | 43,480 |
| Minimum lease payments | | 530,065 | | 66,300 |
| Less: Amount representing interest | | - | | 26,708 |
| Present value of net minimum lease payments | | $530,065 | | $39,592 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Year | | Operating Leases | | Capital Leases |
| | | (In Thousands) |
| | | | | |
| 2013 | | $94,422 | | $6,494 |
| 2014 | | 97,001 | | 4,694 |
| 2015 | | 80,172 | | 4,615 |
| 2016 | | 55,083 | | 4,457 |
| 2017 | | 38,771 | | 4,457 |
| Years thereafter | | 139,560 | | 34,223 |
| Minimum lease payments | | 505,009 | | 58,940 |
| Less: Amount representing interest | | - | | 13,357 |
| Present value of net minimum lease payments | | $505,009 | | $45,583 |
Total rental expenses for all leases (excluding nuclear fuel leases and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $71.6$69.9 million in 2009, $66.42012, $75.3 million in 2008,2011, and $78.8$80.8 million in 2007.2010.
As of December 31, 2009,2012, the Registrant Subsidiaries had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities (excluding nuclear fuel leases and the sale and leaseback transactions) with minimum lease payments as follows:
Capital Leases
Year | | Entergy Arkansas | | Entergy Mississippi | | Entergy Arkansas | | Entergy Mississippi |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| 2010 | | $237 | | $1,800 | |
| 2011 | | 237 | | 1,800 | |
| 2012 | | 237 | | 1,800 | |
| 2013 | | 237 | | 1,800 | | $237 | | $3,370 |
| 2014 | | 237 | | - | | 237 | | 1,570 |
| 2015 | | | 158 | | 1,570 |
| 2016 | | | - | | 1,570 |
| 2017 | | | - | | 1,570 |
| Years thereafter | | 1,383 | | - | | - | | 785 |
| Minimum lease payments | | 2,568 | | 7,200 | | 632 | | 10,435 |
| Less: Amount representing interest | | 1,204 | | 782 | | 367 | | 2,944 |
| Present value of net minimum lease payments | | $1,364 | | $6,418 | | $265 | | $7,491 |
Operating Leases
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| 2013 | | $27,967 | | $12,211 | | $10,776 | | $6,907 | | $2,068 | | $6,537 |
| 2014 | | 26,703 | | 19,311 | | 9,820 | | 6,515 | | 1,898 | | 5,491 |
| 2015 | | 27,808 | | 10,032 | | 8,565 | | 5,503 | | 1,840 | | 3,623 |
| 2016 | | 13,074 | | 9,457 | | 4,967 | | 3,797 | | 1,467 | | 2,475 |
| 2017 | | 7,225 | | 8,477 | | 3,062 | | 2,529 | | 1,045 | | 1,443 |
| Years thereafter | | 4,132 | | 44,264 | | 4,097 | | 5,570 | | 2,192 | | 1,866 |
| Minimum lease payments | | $106,909 | | $103,752 | | $41,287 | | $30,821 | | $10,510 | | $21,435 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Operating Leases
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| 2010 | | $20,983 | | $12,942 | | $8,961 | | $6,381 | | $729 | | $4,289 |
| 2011 | | 21,053 | | 11,273 | | 8,115 | | 4,104 | | 521 | | 4,036 |
| 2012 | | 18,505 | | 10,656 | | 7,010 | | 3,344 | | 382 | | 3,864 |
| 2013 | | 17,090 | | 10,001 | | 6,018 | | 3,009 | | 366 | | 3,786 |
| 2014 | | 15,894 | | 16,853 | | 4,610 | | 2,616 | | 312 | | 2,402 |
| Years thereafter | | 27,096 | | 61,007 | | 5,639 | | 9,066 | | 743 | | 1,724 |
| Minimum lease payments | | $120,621 | | $122,732 | | $40,353 | | $28,520 | | $3,053 | | $20,101 |
Rental Expenses
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2009 | | $12.0 | | $11.6 | | $10.7 | | $5.3 | | $1.6 | | $9.9 | | $1.3 |
| 2008 | | $11.4 | | $11.6 | | $9.9 | | $5.6 | | $1.5 | | $7.8 | | $1.1 |
| 2007 | | $15.9 | | $17.0 | | $10.4 | | $5.4 | | $1.5 | | $11.2 | | $1.3 |
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2012 | | $12.6 | | $11.9 | | $11.2 | | $5.5 | | $1.5 | | $6.4 | | $1.5 |
| 2011 | | $13.4 | | $12.2 | | $12.2 | | $5.2 | | $1.7 | | $8.4 | | $1.6 |
| 2010 | | $13.0 | | $12.5 | | $11.7 | | $5.5 | | $1.7 | | $7.4 | | $1.4 |
In addition to the above rental expense, railcar operating lease payments and oil tank facilities lease payments are recorded in fuel expense in accordance with regulatory treatment. Railcar operating lease payments were $7.2$8.5 million in 2009, $10.22012, $8.3 million in 2008,2011, and $9.0$8.4 million in 20072010 for Entergy Arkansas and $3.1$1.7 million in 2009, $3.42012, $2.0 million in 2008,2011, and $4.8$2.3 million in 20072010 for Entergy Gulf States Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $3.4 million in 2009,2012, $3.4 million in 2008,2011, and $3.4 million in 2007.
Nuclear Fuel Leases
As of December 31, 2009, arrangements to lease nuclear fuel existed in an aggregate amount up to $215 million for Entergy Arkansas, $210 million for Entergy Gulf States Louisiana, $160 million for Entergy Louisiana, and $155 million for System Energy. As of December 31, 2009, the unrecovered cost base of nuclear fuel leases amounted to approximately $173.1 million for Entergy Arkansas, $157.0 million for Entergy Gulf States Louisiana, $122.0 million for Entergy Louisiana, and $75.4 million for System Energy. The lessors finance the acquisition and ownership of nuclear fuel through loans made under revolving credit agreements, the issuance of commercial paper, and the issuance of intermediate-term notes. The credit agreements for Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have a termination date of August 12, 2010. The termination dates may be extended from time to time with the consent of the lenders. The intermediate-term notes issued pursuant to these fuel lease arrangements have varying maturities through July 15, 2014. It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. However, if such additional financing cannot be arranged, the lessee in each case must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations in accordance with the fuel lease.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Lease payments are based on nuclear fuel use. The table below represents the total nuclear fuel lease payments (principal and interest), as well as the separate interest component charged to operations, in 2009, 2008, and 2007 for the four Registrant Subsidiaries that own nuclear power plants:
| | 2009 | | 2008 | | 2007 |
| | Lease Payments | | Interest | | Lease Payments | | Interest | | Lease Payments | | Interest |
| | (In Millions) |
| | | | | | | | | | | | |
| Entergy Arkansas | $79.5 | | $8.1 | | $63.5 | | $4.7 | | $61.7 | | $5.8 |
| Entergy Gulf States Louisiana | 33.9 | | 1.9 | | 29.3 | | 2.5 | | 31.5 | | 2.8 |
| Entergy Louisiana | 50.0 | | 3.3 | | 44.6 | | 3.0 | | 44.2 | | 4.0 |
| System Energy | 50.3 | | 5.4 | | 33.0 | | 2.9 | | 30.4 | | 4.0 |
| Total | $213.7 | | $18.7 | | $170.4 | | $13.1 | | $167.8 | | $16.6 |
Sale and Leaseback Transactions
Waterford 3 Lease Obligations
In 1989, in three separate but substantially identical transactions, Entergy Louisiana sold and leased back undivided interests in Waterford 3 for the aggregate sum of $353.6 million. The interests represent approximately 9.3% of Waterford 3. The leases expire in July 2017. Under certain circumstances, Entergy Louisiana may repurchase the leased interests prior to the end of the term of the leases. At the end of the lease terms, Entergy Louisiana has the option to repurchase the leased interests in Waterford 3 at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate. In the event that Entergy Louisiana does not renew or purchase the interests, Entergy Louisiana would surrender such interests and their associated entitlement of Waterford 3’s capacity and energy.
Entergy Louisiana issued $208.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases.
Upon the occurrence of certain events, Entergy Louisiana may be obligated to assume the outstanding bonds used to finance the purchase of the interests in the unit and to pay an amount sufficient to withdraw from the lease transaction. Such events include lease events of default, events of loss, deemed loss events, or certain adverse "Financial“Financial Events." "Financial Events"” “Financial Events” include, among other things, failure by Entergy Louisiana, following the expiration of any applicable grace or cure period, to maintain (i) total equity capital (including preferred membership interests) at least equal to 30% of adjusted capitalization, or (ii) a fixed charge coverage ratio of at least 1.50 computed on a rolling 12 month basis. As of December 31, 2009,2012, Entergy Louisiana was in compliance with these provisions.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As of December 31, 2009,2012, Entergy Louisiana had future minimum lease payments (reflecting an overall implicit rate of 7.45%) in connection with the Waterford 3 sale and leaseback transactions, which are recorded as long-term debt, as follows:
| | | Amount | | Amount |
| | | (In Thousands) | | (In Thousands) |
| | | | | |
| 2010 | | $35,138 | |
| 2011 | | 50,421 | |
| 2012 | | 39,067 | |
| 2013 | | 26,301 | | $26,301 |
| 2014 | | 31,036 | | 31,036 |
| 2015 | | | 28,827 |
| 2016 | | | 16,938 |
| 2017 | | | 106,335 |
| Years thereafter | | 106,821 | | - |
| Total | | 288,784 | | 209,437 |
| Less: Amount representing interest | | 47,656 | | 46,488 |
| Present value of net minimum lease payments | | $241,128 | | $162,949 |
Grand Gulf Lease Obligations
In December 1988, in two separate but substantially identical transactions, System Energy sold and leased back undivided ownership interests in Grand Gulf for the aggregate sum of $500 million. The interests represent approximately 11.5% of Grand Gulf. The leases expire in July 2015. Under certain circumstances, System Entergy may repurchase the leased interests prior to the end of the term of the leases. At the end of the lease terms, System Energy has the option to repurchase the leased interests in Grand Gulf at fair market value or to renew the leases for either fair market value or, under certain conditions, a fixed rate.
In May 2004,the event that System Energy causeddoes not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf lessors to refinance the outstanding bonds that they had issued to finance the purchase of their undivided interest in Grand Gulf. The refinancing is at a lower interest rate,Gulf’s capacity and System Energy's lease payments have been reduced to reflect the lower interest costs.energy.
System Energy is required to report the sale-leaseback as a financing transaction in its financial statements. For financial reporting purposes, System Energy expenses the interest portion of the lease obligation and the plant depreciation. However, operating revenues include the recovery of the lease payments because the transactions are accounted for as a sale and leaseback for ratemaking purposes. Consistent with a recommendation contained in a FERC audit report, System Energy initially recorded as a net regulatory asset the difference between the recovery of the lease payments and the amounts expensed for interest and depreciation and continues to record this difference as a regulatory asset or liability on an ongoing basis, resulting in a zero net balance for the regulatory asset at the end of the lease term. The amount was a net regulatory liability of $2.5$27.8 million and a net regulatory asset of $19.2$2.0 million as of December 31, 20092012 and 2008,2011, respectively.
As of December 31, 2009,2012, System Energy had future minimum lease payments (reflecting an implicit rate of 5.13%), which are recorded as long-term debt, as follows:
| | | Amount | | Amount |
| | | (In Thousands) | | (In Thousands) |
| | | | | |
| 2010 | | $48,569 | |
| 2011 | | 49,437 | |
| 2012 | | 49,959 | |
| 2013 | | 50,546 | | $50,546 |
| 2014 | | 51,637 | | 51,637 |
| 2015 | | | 52,253 |
| 2016 | | | - |
| 2017 | | | - |
| Years thereafter | | 52,253 | | - |
| Total | | 302,401 | | 154,436 |
| Less: Amount representing interest | | 35,537 | | 15,543 |
| Present value of net minimum lease payments | | $266,864 | | $138,893 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Qualified Pension Plans
Entergy has seven qualified pension plans covering substantially all of its employees: "Entergy“Entergy Corporation Retirement Plan for Non-Bargaining Employees," "Entergy” “Entergy Corporation Retirement Plan for Bargaining Employees," "Entergy” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees," "Entergy” “Entergy Corporation Retirement Plan II for Bargaining Employees," "Entergy” “Entergy Corporation Retirement Plan III," "Entergy” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,"” and "Entergy“Entergy Corporation Retirement Plan IV for Bargaining Employees."” The Registrant Subsidiaries participate in two of these plans: "Entergy“Entergy Corporation Retirement Plan for Non-Bargaining Employees"Employees” and "Entergy“Entergy Corporation Retirement Plan for Bargaining Employees."” Except for the Entergy Corporation Retirement Plan III, the pension plans are noncontributory and provide pension benefits that are based on employees'employees’ credited service and compensation during the final years before retirement. The Entergy Corporation Retirement Plan III includes a mandatory employee contribution of 3% of earnings during the first 10 years of plan participation, and allows voluntary contributions from 1% to 10% of earnings for a limited group of employees.
The assets of the seven qualified pension plans are held in a master trust established by Entergy. Each pension plan maintainshas an undivided beneficial interest in each of the investment accounts of the Master Trustmaster trust that is maintained by J. P. Morgan Chase & Co. (the Trustee.)a trustee. Use of the master trust permits the commingling of the trust assets of the pension plans of Entergy Corporation and its Registrant Subsidiaries for investment and administrative purposes. Although assets are commingled in the master trust, the Trusteetrustee maintains supporting records for the purpose of allocating the equity in net earnings (loss) and the administrative expenses of the investment accounts to the various participating pension plans. The Trustee determines the fair value of the fundtrust assets is determined by the trustee and certain investment managers. The trustee calculates a daily earnings factor, including realized and unrealized gains or losses, collected and accrued income, and administrative expenses, and allocates earnings to each plan in the master trust on a pro rata basis.
Further, within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan'splan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment income and contributions, and decreased for benefit payments. A plan’s investment incomenet income/(loss) (i.e. interest and dividends, realized gains and losses and expense)expenses) is allocated to the Registrant Subsidiaries participating in that plan based on the value of assets for each Registrant Subsidiary at the beginning of the quarter adjusted for contributions and benefit payments made during the quarter.
Entergy Corporation and its subsidiaries fund pension costs in accordance with contribution guidelines established by the Employee Retirement Income Security Act of 1974, as amended, and the Internal Revenue Code of 1986, as amended. The assets of the plans include common and preferred stocks, fixed-income securities, interest in a money market fund, and insurance contracts. The Registrant Subsidiaries'Subsidiaries’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions. Entergy uses a December 31 measurement date for its pension plans.
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefit costs in the Utility's jurisdictions. For the portion of Entergy Gulf States Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive income. Entergy Gulf States Louisiana and Entergy Louisiana recover other postretirement benefit costs on a pay as you go basis and record the unrecognized prior service cost, gains and losses, and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also requires that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.
Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)
Entergy Corporation'sCorporation and its subsidiaries'subsidiaries’ total 2009, 2008,2012, 2011, and 20072010 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
| | | 2009 | | | 2008 | | | 2007 | | | 2012 | | 2011 | | 2010 |
| | | (In Thousands) | | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | | $ | 89,646 | | | $ | 90,392 | | | $ | 96,565 | | | $150,763 | | $121,961 | | $104,956 |
| Interest cost on projected benefit obligation | | | 218,172 | | | | 206,586 | | | | 185,170 | | | 260,929 | | 236,992 | | 231,206 |
| Expected return on assets | | | (249,220 | ) | | | (230,558 | ) | | | (203,521 | ) | | (317,423) | | (301,276) | | (259,608) |
| Amortization of prior service cost | | | 4,997 | | | | 5,063 | | | | 5,531 | | | 2,733 | | 3,350 | | 4,658 |
| Recognized net loss | | | 22,401 | | | | 26,834 | | | | 45,775 | | | 167,279 | | 92,977 | | 65,901 |
| Curtailment loss | | | - | | | | - | | | | 2,336 | | |
| Special termination benefit loss | | | - | | | | - | | | | 4,018 | | |
| Net periodic pension costs | | $ | 85,996 | | | $ | 98,317 | | | $ | 135,874 | | | $264,281 | | $154,004 | | $147,113 |
| | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | - | | | $ | - | | | $ | 11,339 | | |
| Net (gain)/loss | | | 76,799 | | | | 965,069 | | | | (68,853 | ) | |
| Net loss | | | $552,303 | | $1,045,624 | | $232,279 |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | |
| Amortization of prior service credit | | | (4,997 | ) | | | (5,063 | ) | | | (5,531 | ) | |
| Amortization of prior service cost | | | (2,733) | | (3,350) | | (4,658) |
| Amortization of net loss | | | (22,401 | ) | | | (26,834 | ) | | | (45,775 | ) | | (167,279) | | (92,977) | | (65,901) |
| Total | | | 49,401 | | | | 933,172 | | | | (108,820 | ) | | 382,291 | | 949,297 | | 161,720 |
| | | | | | | | | | | | | | | | | | | |
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $ | 135,397 | | | $ | 1,031,489 | | | $ | 27,054 | | | $646,572 | | $1,103,301 | | $308,833 |
| | | | | | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 4,658 | | | $ | 4,997 | | | $ | 5,064 | | | $2,268 | | $2,733 | | $3,350 |
| Net loss | | $ | 65,900 | | | $ | 22,401 | | | $ | 25,641 | | | $219,805 | | $169,064 | | $92,977 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries'Subsidiaries’ total 2009, 2008,2012, 2011, and 20072010 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
2009 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 13,601 | | | $ | 6,993 | | | $ | 7,896 | | | $ | 3,981 | | | $ | 1,701 | | | $ | 3,668 | | | $ | 3,519 | |
Interest cost on projected benefit obligation | | | 47,043 | | | | 21,116 | | | | 27,760 | | | | 14,706 | | | | 5,878 | | | | 15,741 | | | | 8,555 | |
| Expected return on assets | | | (48,749 | ) | | | (30,065 | ) | | | (32,789 | ) | | | (16,943 | ) | | | (7,261 | ) | | | (20,740 | ) | | | (11,064 | ) |
| Amortization of prior service cost | | | 849 | | | | 438 | | | | 474 | | | | 341 | | | | 206 | | | | 321 | | | | 34 | |
| Recognized net loss | | | 7,058 | | | | 319 | | | | 2,817 | | | | 1,289 | | | | 1,225 | | | | 168 | | | | 439 | |
| Net pension cost/(income) | | $ | 19,802 | | | $ | (1,199 | ) | | $ | 6,158 | | | $ | 3,374 | | | $ | 1,749 | | | $ | (842 | ) | | $ | 1,483 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss/(gain) | | $ | 32,528 | | | $ | 36,704 | | | $ | 7,113 | | | $ | 5,609 | | | $ | 724 | | | $ | (3,444 | ) | | $ | 5,076 | |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | | (849 | ) | | | (438 | ) | | | (474 | ) | | | (341 | ) | | | (206 | ) | | | (321 | ) | | | (34 | ) |
| Amortization of net loss | | | (7,058 | ) | | | (319 | ) | | | (2,817 | ) | | | (1,289 | ) | | | (1,225 | ) | | | (168 | ) | | | (439 | ) |
| Total | | $ | 24,621 | | | $ | 35,947 | | | $ | 3,822 | | | $ | 3,979 | | | $ | (707 | ) | | $ | (3,933 | ) | | $ | 4,603 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total recognized as net periodic pension cost/(income), regulatory asset, and/or AOCI (before tax) | | $ | 44,423 | | | $ | 34,748 | | | $ | 9,980 | | | $ | 7,353 | | | $ | 1,042 | | | $ | (4,775 | ) | | $ | 6,086 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 782 | | | $ | 302 | | | $ | 474 | | | $ | 318 | | | $ | 177 | | | $ | 237 | | | $ | 34 | |
| Net loss | | $ | 16,506 | | | $ | 7,621 | | | $ | 8,603 | | | $ | 4,362 | | | $ | 2,544 | | | $ | 3,207 | | | $ | 523 | |
2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $22,169 | | $12,273 | | $14,675 | | $6,410 | | $2,824 | | $5,684 | | $5,920 |
Interest cost on projected benefit obligation | | 55,686 | | 25,679 | | 35,201 | | 16,279 | | 7,608 | | 16,823 | | 12,987 |
| Expected return on assets | | (65,763) | | (34,370) | | (40,836) | | (20,945) | | (8,860) | | (22,325) | | (16,436) |
Amortization of prior service cost | | 200 | | 19 | | 208 | | 30 | | 7 | | 15 | | 13 |
| Recognized net loss | | 40,772 | | 16,173 | | 28,197 | | 10,532 | | 6,878 | | 10,179 | | 9,001 |
| Net pension cost | | $53,064 | | $19,774 | | $37,445 | | $12,306 | | $8,457 | | $10,376 | | $11,485 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Net loss | | $105,133 | | $77,207 | | $76,163 | | $27,106 | | $14,282 | | $28,745 | | $10,266 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of prior service cost | | (200) | | (19) | | (208) | | (30) | | (7) | | (15) | | (13) |
| Amortization of net loss | | (40,772) | | (16,173) | | (28,197) | | (10,532) | | (6,878) | | (10,179) | | (9,001) |
| Total | | $64,161 | | $61,015 | | $47,758 | | $16,544 | | $7,397 | | $18,551 | | $1,252 |
| | | | | | | | | | | | | | | |
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $117,225 | | $80,789 | | $85,203 | | $28,850 | | $15,854 | | $28,927 | | $12,737 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Prior service cost | | $23 | | $9 | | $83 | | $10 | | $2 | | $6 | | $10 |
| Net loss | | $50,175 | | $23,731 | | $34,906 | | $13,375 | | $8,046 | | $13,494 | | $9,717 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2008 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 14,335 | | | $ | 7,363 | | | $ | 8,230 | | | $ | 4,251 | | | $ | 1,779 | | | $ | 3,874 | | | $ | 3,719 | |
Interest cost on projected benefit obligation | | | 46,464 | | | | 20,189 | | | | 27,135 | | | | 14,507 | | | | 5,660 | | | | 15,528 | | | | 7,749 | |
| Expected return on assets | | | (47,060 | ) | | | (28,658 | ) | | | (32,535 | ) | | | (16,299 | ) | | | (7,355 | ) | | | (20,188 | ) | | | (9,810 | ) |
| Amortization of prior service cost | | | 892 | | | | 438 | | | | 478 | | | | 361 | | | | 205 | | | | 321 | | | | 34 | |
| Recognized net loss | | | 9,212 | | | | 461 | | | | 3,679 | | | | 1,941 | | | | 1,280 | | | | 621 | | | | 366 | |
| Net pension cost/(income) | | $ | 23,843 | | | $ | (207 | ) | | $ | 6,987 | | | $ | 4,761 | | | $ | 1,569 | | | $ | 156 | | | $ | 2,058 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | | $ | 178,674 | | | $ | 118,804 | | | $ | 131,649 | | | $ | 64,245 | | | $ | 30,687 | | | $ | 81,016 | | | $ | 37,700 | |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | | (892 | ) | | | (438 | ) | | | (478 | ) | | | (361 | ) | | | (205 | ) | | | (321 | ) | | | (34 | ) |
| Amortization of net loss | | | (9,212 | ) | | | (461 | ) | | | (3,679 | ) | | | (1,941 | ) | | | (1,280 | ) | | | (621 | ) | | | (366 | ) |
| Total | | $ | 168,570 | | | $ | 117,905 | | | $ | 127,492 | | | $ | 61,943 | | | $ | 29,202 | | | $ | 80,074 | | | $ | 37,300 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $ | 192,413 | | | $ | 117,698 | | | $ | 134,479 | | | $ | 66,704 | | | $ | 30,771 | | | $ | 80,230 | | | $ | 39,358 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 849 | | | $ | 438 | | | $ | 474 | | | $ | 341 | | | $ | 206 | | | $ | 321 | | | $ | 34 | |
| Net loss | | $ | 7,063 | | | $ | 323 | | | $ | 2,823 | | | $ | 1,299 | | | $ | 1,216 | | | $ | 200 | | | $ | 433 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2007 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 14,550 | | | $ | 12,043 | | | $ | 8,924 | | | $ | 4,357 | | | $ | 1,878 | | | $ | 4,048 | | | $ | 4,083 | |
Interest cost on projected benefit obligation | | | 41,992 | | | | 32,556 | | | | 25,003 | | | | 13,484 | | | | 5,040 | | | | 13,757 | | | | 6,841 | |
| Expected return on assets | | | (44,037 | ) | | | (43,001 | ) | | | (31,232 | ) | | | (15,349 | ) | | | (5,786 | ) | | | (18,145 | ) | | | (8,543 | ) |
| Amortization of prior service cost | | | 1,649 | | | | 1,217 | | | | 640 | | | | 455 | | | | 178 | | | | 530 | | | | 49 | |
| Recognized net loss | | | 10,885 | | | | 2,492 | | | | 5,733 | | | | 2,998 | | | | 1,471 | | | | 1,051 | | | | 600 | |
| Special termination benefit loss | | | 1,538 | | | | 443 | | | | 607 | | | | - | | | | - | | | | - | | | | 211 | |
| Net pension cost | | $ | 26,577 | | | $ | 5,750 | | | $ | 9,675 | | | $ | 5,945 | | | $ | 2,781 | | | $ | 1,241 | | | $ | 3,241 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net (gain)/loss | | $ | (1,470 | ) | | $ | (7,115 | ) | | $ | (9,098 | ) | | $ | (5,388 | ) | | $ | 1,221 | | | $ | 6,774 | | | $ | (1,405 | ) |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | | (1,649 | ) | | | (1,218 | ) | | | (640 | ) | | | (455 | ) | | | (178 | ) | | | (530 | ) | | | (49 | ) |
| Amortization of net loss | | | (10,885 | ) | | | (2,492 | ) | | | (5,733 | ) | | | (2,998 | ) | | | (1,471 | ) | | | (1,051 | ) | | | (600 | ) |
| Total | | $ | (14,004 | ) | | $ | (10,825 | ) | | $ | (15,471 | ) | | $ | (8,841 | ) | | $ | (428 | ) | | $ | 5,193 | | | $ | (2,054 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $ | 12,573 | | | $ | (5,075 | ) | | $ | (5,796 | ) | | $ | (2,896 | ) | | $ | 2,353 | | | $ | 6,434 | | | $ | 1,187 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 892 | | | $ | 438 | | | $ | 478 | | | $ | 361 | | | $ | 207 | | | $ | 321 | | | $ | 34 | |
| Net loss | | $ | 8,611 | | | $ | 654 | | | $ | 3,196 | | | $ | 1,704 | | | $ | 1,201 | | | $ | 177 | | | $ | 360 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $18,072 | | $9,848 | | $11,543 | | $5,308 | | $2,242 | | $4,788 | | $4,941 |
Interest cost on projected benefit obligation | | 51,965 | | 23,713 | | 32,636 | | 15,637 | | 7,050 | | 15,971 | | 11,758 |
| Expected return on assets | | (62,434) | | (33,358) | | (38,866) | | (20,152) | | (8,455) | | (22,005) | | (15,138) |
Amortization of prior service cost | | 459 | | 79 | | 280 | | 152 | | 35 | | 65 | | 16 |
| Recognized net loss | | 25,681 | | 9,118 | | 17,990 | | 6,717 | | 4,666 | | 5,579 | | 5,284 |
| Net pension cost | | $33,743 | | $9,400 | | $23,583 | | $7,662 | | $5,538 | | $4,398 | | $6,861 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Net loss | | $217,989 | | $102,329 | | $137,100 | | $56,714 | | $29,297 | | $64,662 | | $52,876 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of prior service cost | | (459) | | (79) | | (280) | | (152) | | (35) | | (65) | | (16) |
| Amortization of net loss | | (25,681) | | (9,118) | | (17,990) | | (6,717) | | (4,666) | | (5,579) | | (5,284) |
| Total | | $191,849 | | $93,132 | | $118,830 | | $49,845 | | $24,596 | | $59,018 | | $47,576 |
| | | | | | | | | | | | | | | |
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $225,592 | | $102,532 | | $142,413 | | $57,507 | | $30,134 | | $63,416 | | $54,437 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Prior service cost | | $200 | | $19 | | $208 | | $30 | | $7 | | $15 | | $13 |
| Net loss | | $41,309 | | $16,295 | | $28,486 | | $10,667 | | $6,935 | | $10,261 | | $9,135 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $15,775 | | $8,462 | | $9,770 | | $4,651 | | $2,063 | | $4,267 | | $4,132 |
Interest cost on projected benefit obligation | | 49,277 | | 24,377 | | 28,541 | | 15,230 | | 6,040 | | 15,869 | | 9,009 |
| Expected return on assets | | (50,635) | | (30,752) | | (32,775) | | (17,252) | | (7,236) | | (20,549) | | (11,808) |
Amortization of prior service cost | | 782 | | 302 | | 474 | | 318 | | 177 | | 237 | | 34 |
| Recognized net loss | | 16,506 | | 7,622 | | 8,604 | | 4,361 | | 2,544 | | 3,208 | | 523 |
| Net pension cost | | $31,705 | | $10,011 | | $14,614 | | $7,308 | | $3,588 | | $3,032 | | $1,890 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Net loss | | $97,117 | | $4,748 | | $99,129 | | $21,801 | | $22,600 | | $17,316 | | $56,756 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of prior service cost | | (782) | | (302) | | (474) | | (318) | | (177) | | (237) | | (34) |
| Amortization of net loss | | (16,506) | | (7,622) | | (8,604) | | (4,361) | | (2,544) | | (3,208) | | (523) |
| Total | | $79,829 | | ($3,176) | | $90,051 | | $17,122 | | $19,879 | | $13,871 | | $56,199 |
| | | | | | | | | | | | | | | |
Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | | $111,534 | | $6,835 | | $104,665 | | $24,430 | | $23,467 | | $16,903 | | $58,089 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Prior service cost | | $459 | | $79 | | $280 | | $152 | | $35 | | $65 | | $16 |
| Net loss | | $25,681 | | $9,118 | | $17,990 | | $6,717 | | $4,666 | | $5,579 | | $5,284 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified Pension Obligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet for Entergy Corporation and its Subsidiaries as of December 31, 20092012 and 20082011
| | | December 31, | | | December 31, |
| | | 2009 | | | 2008 | | | 2012 | | 2011 |
| | | (In Thousands) | | | (In Thousands) |
| Change in Projected Benefit Obligation (PBO) | | | | | | | | | | |
| Balance at beginning of year | | $ | 3,305,315 | | | $ | 3,247,724 | | | $5,187,635 | | $4,301,218 |
| Service cost | | | 89,646 | | | | 90,392 | | | 150,763 | | 121,961 |
| Interest cost | | | 218,172 | | | | 206,586 | | | 260,929 | | 236,992 |
| Actuarial loss/(gain) | | | 385,221 | | | | (89,124 | ) | |
| Actuarial loss | | | 693,017 | | 703,895 |
| Employee contributions | | | 852 | | | | 902 | | | 789 | | 828 |
| Benefits paid | | | (161,462 | ) | | | (151,165 | ) | | (196,494) | | (177,259) |
| Balance at end of year | | $ | 3,837,744 | | | $ | 3,305,315 | | | $6,096,639 | | $5,187,635 |
| | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 2,078,252 | | | $ | 2,764,383 | | | $3,399,916 | | $3,216,268 |
| Actual return on plan assets | | | 557,642 | | | | (823,636 | ) | | 458,137 | | (40,453) |
| Employer contributions | | | 131,990 | | | | 287,768 | | | 170,512 | | 400,532 |
| Employee contributions | | | 852 | | | | 902 | | | 789 | | 828 |
| Acquisition | | | - | | | | - | | |
| Benefits paid | | | (161,462 | ) | | | (151,165 | ) | | (196,494) | | (177,259) |
| Fair value of assets at end of year | | $ | 2,607,274 | | | $ | 2,078,252 | | | $3,832,860 | | $3,399,916 |
| | | | | | | | | | | | | |
| Funded status | | $ | (1,230,470 | ) | | $ | (1,227,063 | ) | | ($2,263,779) | | ($1,787,719) |
| | | | | | | | | | | | | |
| Amount recognized in the balance sheet | | | | | | | | | | | | |
| Non-current liabilities | | $ | (1,230,470 | ) | | $ | (1,227,063 | ) | | ($2,263,779) | | ($1,787,719) |
| | | | | | | | | | | | | |
| Amount recognized as a regulatory asset | | | | | | | | | | | | |
| Prior service cost | | $ | 16,376 | | | $ | 20,548 | | | $308 | | $9,836 |
| Net loss | | �� | 1,183,824 | | | | 1,150,298 | | | 2,352,234 | | 2,048,743 |
| | | $ | 1,200,200 | | | $ | 1,170,846 | | | $2,352,542 | | $2,058,579 |
| Amount recognized as AOCI (before tax) | | | | | | | | | | | | |
| Prior service cost | | $ | 4,116 | | | $ | 4,941 | | | $9,444 | | $2,648 |
| Net loss | | | 297,507 | | | | 276,635 | | | 633,146 | | 551,613 |
| | | $ | 301,623 | | | $ | 281,576 | | | $642,590 | | $554,261 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognized in the Balance Sheet for the Registrant Subsidiaries as of December 31, 20092012 and 20082011
2009 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | | |
2012 | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | | (In Thousands) |
| Change in Projected Benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Obligation (PBO) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | | $ | 717,104 | | | $ | 320,220 | | | $ | 423,322 | | | $ | 224,605 | | | $ | 89,315 | | | $ | 240,666 | | | $ | 128,540 | | | $1,116,572 | | $512,432 | | $704,748 | | $326,377 | | $151,966 | | $337,669 | | $258,268 |
| Service cost | | | 13,601 | | | | 6,993 | | | | 7,896 | | | | 3,981 | | | | 1,701 | | | | 3,668 | | | | 3,519 | | | 22,169 | | 12,273 | | 14,675 | | 6,410 | | 2,824 | | 5,684 | | 5,920 |
| Interest cost | | | 47,043 | | | | 21,116 | | | | 27,760 | | | | 14,706 | | | | 5,878 | | | | 15,741 | | | | 8,555 | | | 55,686 | | 25,679 | | 35,201 | | 16,279 | | 7,608 | | 16,823 | | 12,987 |
| Actuarial loss | | | 90,303 | | | | 73,059 | | | | 46,963 | | | | 25,774 | | | | 9,000 | | | | 21,311 | | | | 13,423 | | | 134,691 | | 92,275 | | 93,817 | | 36,329 | | 18,000 | | 38,328 | | 13,691 |
| Employee contribution | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 2 | | |
| Benefits paid | | | (43,790 | ) | | | (16,160 | ) | | | (25,438 | ) | | | (14,009 | ) | | | (4,569 | ) | | | (15,015 | ) | | | (4,652 | ) | | (54,232) | | (19,591) | | (30,696) | | (15,543) | | (5,813) | | (16,328) | | (8,025) |
| Balance at end of year | | $ | 824,261 | | | $ | 405,228 | | | $ | 480,503 | | | $ | 255,057 | | | $ | 101,325 | | | $ | 266,371 | | | $ | 149,387 | | | $1,274,886 | | $623,068 | | $817,745 | | $369,852 | | $174,585 | | $382,176 | | $282,841 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 407,158 | | | $ | 253,966 | | | $ | 273,473 | | | $ | 142,916 | | | $ | 60,104 | | | $ | 175,551 | | | $ | 71,648 | | | $707,275 | | $366,555 | | $432,418 | | $223,981 | | $94,202 | | $237,438 | | $147,091 |
| Actual return on plan assets | | | 106,556 | | | | 66,610 | | | | 72,862 | | | | 37,186 | | | | 15,404 | | | | 45,823 | | | | 19,316 | | | 95,321 | | 49,438 | | 58,489 | | 30,169 | | 12,578 | | 31,909 | | 19,860 |
| Employer contributions | | | 24,808 | | | | 6,029 | | | | 7,623 | | | | 5,819 | | | | 1,107 | | | | 3,577 | | | | 4,747 | | | 37,163 | | 13,569 | | 28,816 | | 9,665 | | 5,811 | | 9,091 | | 9,771 |
| Employee contribution | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 2 | | |
| Benefits paid | | | (43,790 | ) | | | (16,160 | ) | | | (25,438 | ) | | | (14,009 | ) | | | (4,569 | ) | | | (15,015 | ) | | | (4,652 | ) | | (54,232) | | (19,591) | | (30,696) | | (15,543) | | (5,813) | | (16,328) | | (8,025) |
| Fair value of assets at end of year | | $ | 494,732 | | | $ | 310,445 | | | $ | 328,520 | | | $ | 171,912 | | | $ | 72,046 | | | $ | 209,936 | | | $ | 91,061 | | | $785,527 | | $409,971 | | $489,027 | | $248,272 | | $106,778 | | $262,110 | | $168,697 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded status | | $ | (329,529 | ) | | $ | (94,783 | ) | | $ | (151,983 | ) | | $ | (83,145 | ) | | $ | (29,279 | ) | | $ | (56,435 | ) | | $ | (58,326 | ) | | ($489,359) | | ($213,097) | | ($328,718) | | ($121,580) | | ($67,807) | | ($120,066) | | ($114,144) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current assets | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | |
| Non-current liabilities | | | (329,529 | ) | | | (94,783 | ) | | | (151,983 | ) | | | (83,145 | ) | | | (29,279 | ) | | | (56,435 | ) | | | (58,326 | ) | | ($489,359) | | ($213,097) | | ($328,718) | | ($121,580) | | ($67,807) | | ($120,066) | | ($114,144) |
| Total funded status | | $ | (329,529 | ) | | $ | (94,783 | ) | | $ | (151,983 | ) | | $ | (83,145 | ) | | $ | (29,279 | ) | | $ | (56,435 | ) | | $ | (58,326 | ) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized as regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 1,464 | | | $ | 331 | | | $ | 1,045 | | | $ | 509 | | | $ | 222 | | | $ | 324 | | | $ | 69 | | | $23 | | $8 | | $83 | | $10 | | $2 | | $7 | | $6 |
| Net loss | | | 346,511 | | | | 141,661 | | | | 199,201 | | | | 101,893 | | | | 50,980 | | | | 97,832 | | | | 61,186 | | | 683,790 | | 283,847 | | 456,800 | | 185,903 | | 103,072 | | 189,589 | | 166,276 |
| | | $ | 347,975 | | | $ | 141,992 | | | $ | 200,246 | | | $ | 102,402 | | | $ | 51,202 | | | $ | 98,156 | | | $ | 61,255 | | | $683,813 | | $283,855 | | $456,883 | | $185,913 | | $103,074 | | $189,596 | | $166,282 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized as AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | - | | | $ | 78 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $- | | $1 | | $- | | $- | | $- | | $- | | $- |
| Net loss | | | - | | | | 33,229 | | | | - | | | | - | | | | - | | | | - | | | | - | | | - | | 42,414 | | - | | - | | - | | - | | - |
| | | $ | - | | | $ | 33,307 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $- | | $42,415 | | $- | | $- | | $- | | $- | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2008 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | | |
2011 | | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | | (In Thousands) |
| Change in Projected Benefit | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Obligation (PBO) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | | $ | 734,358 | | | $ | 317,997 | | | $ | 429,387 | | | $ | 229,962 | | | $ | 89,132 | | | $ | 245,910 | | | $ | 120,517 | | | $950,595 | | $431,870 | | $596,730 | | $286,179 | | $128,477 | | $292,551 | | $213,098 |
| Service cost | | | 14,335 | | | | 7,363 | | | | 8,230 | | | | 4,251 | | | | 1,779 | | | | 3,874 | | | | 3,719 | | | 18,072 | | 9,848 | | 11,543 | | 5,308 | | 2,242 | | 4,788 | | 4,941 |
| Interest cost | | | 46,464 | | | | 20,189 | | | | 27,135 | | | | 14,507 | | | | 5,660 | | | | 15,528 | | | | 7,749 | | | 51,965 | | 23,713 | | 32,636 | | 15,637 | | 7,050 | | 15,971 | | 11,758 |
| Actuarial gain | | | (34,504 | ) | | | (10,785 | ) | | | (16,436 | ) | | | (10,447 | ) | | | (1,838 | ) | | | (10,280 | ) | | | (10 | ) | |
| Employee contribution | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 4 | | |
| Actuarial loss | | | 146,514 | | 65,000 | | 93,175 | | 33,865 | | 19,695 | | 40,122 | | 35,775 |
| Benefits paid | | | (43,549 | ) | | | (14,544 | ) | | | (24,994 | ) | | | (13,668 | ) | | | (5,418 | ) | | | (14,366 | ) | | | (3,439 | ) | | (50,574) | | (17,999) | | (29,336) | | (14,612) | | (5,498) | | (15,763) | | (7,304) |
| Balance at end of year | | $ | 717,104 | | | $ | 320,220 | | | $ | 423,322 | | | $ | 224,605 | | | $ | 89,315 | | | $ | 240,666 | | | $ | 128,540 | | | $1,116,572 | | $512,432 | | $704,748 | | $326,377 | | $151,966 | | $337,669 | | $258,268 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 577,959 | | | $ | 335,180 | | | $ | 413,964 | | | $ | 203,289 | | | $ | 90,692 | | | $ | 242,144 | | | $ | 97,170 | | | $646,491 | | $361,207 | | $406,216 | | $212,122 | | $88,688 | | $237,502 | | $128,007 |
| Actual return on plan assets | | | (166,118 | ) | | | (100,930 | ) | | | (115,550 | ) | | | (58,393 | ) | | | (25,170 | ) | | | (71,109 | ) | | | (27,899 | ) | | (9,042) | | (3,971) | | (5,059) | | (2,698) | | (1,148) | | (2,536) | | (1,963) |
| Employer contributions | | | 38,866 | | | | 34,260 | | | | 53 | | | | 11,688 | | | | - | | | | 18,882 | | | | 5,812 | | | 120,400 | | 27,318 | | 60,597 | | 29,169 | | 12,160 | | 18,235 | | 28,351 |
| Employee contribution | | | - | | | | - | | | | - | | | | - | | | | - | | | | - | | | | 4 | | |
| Benefits paid | | | (43,549 | ) | | | (14,544 | ) | | | (24,994 | ) | | | (13,668 | ) | | | (5,418 | ) | | | (14,366 | ) | | | (3,439 | ) | | (50,574) | | (17,999) | | (29,336) | | (14,612) | | (5,498) | | (15,763) | | (7,304) |
| Fair value of assets at end of year | | $ | 407,158 | | | $ | 253,966 | | | $ | 273,473 | | | $ | 142,916 | | | $ | 60,104 | | | $ | 175,551 | | | $ | 71,648 | | | $707,275 | | $366,555 | | $432,418 | | $223,981 | | $94,202 | | $237,438 | | $147,091 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded status | | $ | (309,946 | ) | | $ | (66,254 | ) | | $ | (149,849 | ) | | $ | (81,689 | ) | | $ | (29,211 | ) | | $ | (65,115 | ) | | $ | (56,892 | ) | | ($409,297) | | ($145,877) | | ($272,330) | | ($102,396) | | ($57,764) | | (($100,231) | | ($111,177) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current assets | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | |
| Non-current liabilities | | | (309,946 | ) | | | (66,254 | ) | | | (149,849 | ) | | | (81,689 | ) | | | (29,211 | ) | | | (65,115 | ) | | | (56,892 | ) | | ($409,297) | | ($145,877) | | ($272,330) | | ($102,396) | | ($57,764) | | ($100,231) | | ($111,177) |
| Total funded status | | $ | (309,946 | ) | | $ | (66,254 | ) | | $ | (149,849 | ) | | $ | (81,689 | ) | | $ | (29,211 | ) | | $ | (65,115 | ) | | $ | (56,892 | ) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized as regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | 2,313 | | | $ | 720 | | | $ | 1,520 | | | $ | 849 | | | $ | 428 | | | $ | 645 | | | $ | 103 | | | $223 | | $23 | | $291 | | $39 | | $10 | | $22 | | $19 |
| Net loss | | | 321,073 | | | | 117,891 | | | | 195,127 | | | | 97,651 | | | | 51,348 | | | | 101,772 | | | | 56,455 | | | 619,430 | | 214,833 | | 408,835 | | 169,329 | | 95,667 | | 171,023 | | 165,011 |
| | | $ | 323,386 | | | $ | 118,611 | | | $ | 196,647 | | | $ | 98,500 | | | $ | 51,776 | | | $ | 102,417 | | | $ | 56,558 | | | $619,653 | | $214,856 | | $409,126 | | $169,368 | | $95,677 | | $171,045 | | $165,030 |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized as AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | | $ | - | | | $ | 127 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $- | | $6 | | $- | | $- | | $- | | $- | | $- |
| Net loss | | | - | | | | 20,804 | | | | - | | | | - | | | | - | | | | - | | | | - | | | - | | 50,393 | | - | | - | | - | | - | | - |
| | | $ | - | | | $ | 20,931 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $- | | $50,399 | | $- | | $- | | $- | | $- | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefits
Entergy also currently provides health care and life insurance benefits for retired employees. Substantially all employees may become eligible for these benefits if they reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy uses a December 31 measurement date for its postretirement benefit plans.
Effective January 1, 1993, Entergy adopted an accounting standard requiring a change from a cash method to an accrual method of accounting for postretirement benefits other than pensions. At January 1, 1993, the actuarially determined accumulated postretirement benefit obligation (APBO) earned by retirees and active employees was estimated to be approximately $241.4 million for Entergy (other than the former Entergy Gulf States) and $128 million for the former Entergy Gulf States (now split into Entergy Gulf States Louisiana and Entergy Texas.)Texas). Such obligations are being amortized over a 20-year period that began in 1993.1993 and ended in 2012. For the most part, the Registrant Subsidiaries recover accrued other postretirement benefit costs from customers and are required to contribute the other postretirement benefits collected in rates to an external trust.
Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates. Entergy Arkansas began recovery in 1998, pursuant to an APSC order. This order also allowed Entergy Arkansas to amortize a regulatory asset (representing the difference between other postretirement benefit costs and cash expenditures for other postretirement benefits incurred for a five-year period that began January 1, 1993)from 1993 through 1997) over a 15-year period that began in January 1998.1998 and ended in December 2012.
The LPSC ordered Entergy Gulf States Louisiana and Entergy Louisiana to continue the use of the pay-as-you-go method for ratemaking purposes for postretirement benefits other than pensions. However, the LPSC retains the flexibility to examine individual companies'companies’ accounting for other postretirement benefits to determine if special exceptions to this order are warranted.
Pursuant to regulatory directives, Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy contribute the other postretirement benefit costs collected in rates into external trusts. System Energy is funding, on behalf of Entergy Operations, other postretirement benefits associated with Grand Gulf.
Trust assets contributed by participating Registrant Subsidiaries are in three bank-administered master trusts, established by Entergy Corporation and maintained by The Bank of New York Mellon (the Trustee.)a trustee. Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets. Use of theseThe assets in the master trusts permits the commingling of the trust assetsare commingled for investment and administrative purposes. Although assets are commingled, the Trustee maintains supporting records are maintained for the purpose of allocating the beneficial interest in net earnings earnings/(losses) and the administrative expenses of the investment accounts to the various participating plans and participating Registrant Subsidiaries. Beneficial interest in an investment account’s net earnings (losses)income/(loss) is comprised of interest and dividends, and realized and unrealized gains and losses.losses, and expenses. Beneficial interest from these investments is allocated monthly to the plans and participating Registrant Subsidiary based on itstheir portion of net assets in the pooled accounts.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Components of Net Other Postretirement Benefit Cost and Other Amounts Recognized as a Regulatory Asset and/or AOCI
Entergy Corporation'sCorporation’s and its subsidiaries'subsidiaries’ total 2009, 2008,2012, 2011, and 20072010 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
| | | 2009 | | | 2008 | | | 2007 | | | 2012 | | 2011 | | 2010 |
| | | (In Thousands) | | | (In Thousands) |
| Other post retirement costs: | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | | $ | 46,765 | | | $ | 47,198 | | | $ | 44,137 | | | $68,883 | | $59,340 | | $52,313 |
| Interest cost on APBO | | | 75,265 | | | | 71,295 | | | | 63,231 | | | 82,561 | | 74,522 | | 76,078 |
| Expected return on assets | | | (23,484 | ) | | | (28,109 | ) | | | (25,298 | ) | | (34,503) | | (29,477) | | (26,213) |
| Amortization of transition obligation | | | 3,732 | | | | 3,827 | | | | 3,831 | | | 3,177 | | 3,183 | | 3,728 |
| Amortization of prior service credit | | | (16,096 | ) | | | (16,417 | ) | | | (15,836 | ) | | (18,163) | | (14,070) | | (12,060) |
| Recognized net loss | | | 18,970 | | | | 15,565 | | | | 18,972 | | | 36,448 | | 21,192 | | 17,270 |
| Special termination benefits | | | - | | | | - | | | | 603 | | |
| Net other postretirement benefit cost | | $ | 105,152 | | | $ | 93,359 | | | $ | 89,640 | | | $138,403 | | $114,690 | | $111,116 |
| | | | | | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and /or AOCI (before tax) | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | |
| Prior service credit for period | | $ | - | | | $ | (5,422 | ) | | $ | (3,520 | ) | | $- | | ($29,507) | | ($50,548) |
| Net (gain)/loss | | | 24,983 | | | | 59,291 | | | | (15,013 | ) | |
| Net loss | | | 92,584 | | 236,594 | | 82,189 |
| Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year: | | | | | | | | | | | | | | | | | | |
| Amortization of transition obligation | | | (3,732 | ) | | | (3,827 | ) | | | (3,831 | ) | | (3,177) | | (3,183) | | (3,728) |
| Amortization of prior service credit | | | 16,096 | | | | 16,417 | | | | 15,836 | | | 18,163 | | 14,070 | | 12,060 |
| Amortization of net loss | | | (18,970 | ) | | | (15,565 | ) | | | (18,972 | ) | | (36,448) | | (21,192) | | (17,270) |
| Total | | $ | 18,377 | | | $ | 50,894 | | | $ | (25,500 | ) | | $71,122 | | $196,782 | | $22,703 |
Total recognized as net periodic benefit cost, regulatory asset, and/or AOCI (before tax) | | $ | 123,529 | | | $ | 144,253 | | | $ | 64,140 | | | $209,525 | | $311,472 | | $133,819 |
| | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | 3,728 | | | $ | 3,729 | | | $ | 3,831 | | | $- | | $3,177 | | $3,183 |
| Prior service credit | | $ | (12,060 | ) | | $ | (17,519 | ) | | $ | (16,417 | ) | | ($13,336) | | ($18,163) | | ($14,070) |
| Net loss | | $ | 17,270 | | | $ | 19,018 | | | $ | 15,676 | | | $45,217 | | $43,127 | | $21,192 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total 2009, 2008,2012, 2011, and 20072010 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, included the following components:
2009 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | | | | System Energy | |
| | | (In Thousands) | |
| Other post retirement costs: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 7,058 | | | $ | 4,783 | | | $ | 4,589 | | | $ | 2,119 | | | $ | 1,242 | | | $ | 2,475 | | | $ | 2,051 | |
| Interest cost on APBO | | | 15,036 | | | | 8,020 | | | | 9,188 | | | | 4,690 | | | | 3,869 | | | | 5,959 | | | | 2,421 | |
| Expected return on assets | | | (8,570 | ) | | | - | | | | - | | | | (3,027 | ) | | | (2,734 | ) | | | (6,222 | ) | | | (1,655 | ) |
| Amortization of transition obligation | | | 821 | | | | 239 | | | | 382 | | | | 352 | | | | 1,662 | | | | 265 | | | | 9 | |
| Amortization of prior service cost/(credit) | | | (788 | ) | | | (306 | ) | | | 467 | | | | (246 | ) | | | 361 | | | | 76 | | | | (980 | ) |
| Recognized net loss | | | 8,347 | | | | 1,975 | | | | 2,215 | | | | 2,629 | | | | 1,522 | | | | 3,194 | | | | 1,277 | |
| Net other postretirement benefit cost | | $ | 21,904 | | | $ | 14,711 | | | $ | 16,841 | | | $ | 6,517 | | | $ | 5,922 | | | $ | 5,747 | | | $ | 3,123 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit for period | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Net (gain)/loss | | | (9,364 | ) | | | 14,746 | | | | 6,080 | | | | (5,919 | ) | | | (3,474 | ) | | | 2,349 | | | | 2,166 | |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of transition obligation | | | (821 | ) | | | (239 | ) | | | (382 | ) | | | (352 | ) | | | (1,662 | ) | | | (265 | ) | | | (9 | ) |
| Amortization of prior service cost/(credit) | | | 788 | | | | 306 | | | | (467 | ) | | | 246 | | | | (361 | ) | | | (76 | ) | | | 980 | |
| Amortization of net loss | | | (8,347 | ) | | | (1,975 | ) | | | (2,215 | ) | | | (2,629 | ) | | | (1,522 | ) | | | (3,194 | ) | | | (1,277 | ) |
| Total | | $ | (17,744 | ) | | $ | 12,838 | | | $ | 3,016 | | | $ | (8,654 | ) | | $ | (7,019 | ) | | $ | (1,186 | ) | | $ | 1,860 | |
| Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $ | 4,160 | | | $ | 27,549 | | | $ | 19,857 | | | $ | (2,137 | ) | | $ | (1,097 | ) | | $ | 4,561 | | | $ | 4,983 | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition (asset)/obligation | | $ | 821 | | | $ | 238 | | | $ | 382 | | | $ | 351 | | | $ | 1,661 | | | $ | 265 | | | $ | 8 | |
| Prior service cost/(credit) | | $ | (786 | ) | | $ | (306 | ) | | $ | 467 | | | $ | (246 | ) | | $ | 361 | | | $ | 76 | | | $ | (763 | ) |
| Net loss | | $ | 6,758 | | | $ | 2,653 | | | $ | 2,440 | | | $ | 1,903 | | | $ | 1,095 | | | $ | 3,008 | | | $ | 1,301 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| Other post retirement costs: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $9,089 | | $7,521 | | $7,796 | | $3,093 | | $1,689 | | $3,651 | | $3,293 |
| Interest cost on APBO | | 14,452 | | 9,590 | | 9,781 | | 4,716 | | 3,422 | | 6,650 | | 3,028 |
| Expected return on assets | | (14,029) | | - | | - | | (4,521) | | (3,711) | | (8,415) | | (2,601) |
Amortization of transition obligation | | 820 | | 238 | | 382 | | 351 | | 1,189 | | 187 | | 8 |
Amortization of prior service cost/(credit) | | (530) | | (824) | | (247) | | (139) | | 38 | | (428) | | (63) |
| Recognized net loss | | 8,305 | | 4,737 | | 4,359 | | 2,920 | | 1,559 | | 4,320 | | 1,970 |
Net other postretirement benefit cost | | $18,107 | | $21,262 | | $22,071 | | $6,420 | | $4,186 | | $5,965 | | $5,635 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Net loss | | $9,066 | | $5,818 | | $16,215 | | $271 | | $2,260 | | $191 | | $2,043 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of transition obligation | | (820) | | (238) | | (382) | | (351) | | (1,189) | | (187) | | (8) |
Amortization of prior service cost/(credit) | | 530 | | 824 | | 247 | | 139 | | (38) | | 428 | | 63 |
| Amortization of net loss | | (8,305) | | (4,737) | | (4,359) | | (2,920) | | (1,559) | | (4,320) | | (1,970) |
| Total | | $471 | | $1,667 | | $11,721 | | ($2,861) | | ($526) | | ($3,888) | | $128 |
Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $18,578 | | $22,929 | | $33,792 | | $3,559 | | $3,660 | | $2,077 | | $5,763 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Prior service cost/(credit) | | ($530) | | ($824) | | ($247) | | ($139) | | $38 | | ($428) | | ($62) |
| Net loss | | $8,163 | | $4,693 | | $5,149 | | $2,650 | | $1,587 | | $3,905 | | $1,915 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2008 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | | | | System Energy | |
| | | (In Thousands) | |
| Other post retirement costs: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 6,824 | | | $ | 5,003 | | | $ | 4,394 | | | $ | 2,057 | | | $ | 1,179 | | | $ | 2,423 | | | $ | 2,053 | |
| Interest cost on APBO | | | 13,772 | | | | 7,668 | | | | 8,746 | | | | 4,563 | | | | 3,810 | | | | 5,759 | | | | 2,124 | |
| Expected return on assets | | | (9,966 | ) | | | - | | | | - | | | | (3,620 | ) | | | (3,155 | ) | | | (7,538 | ) | | | (2,043 | ) |
| Amortization of transition obligation | | | 821 | | | | 337 | | | | 382 | | | | 351 | | | | 1,661 | | | | 265 | | | | 8 | |
| Amortization of prior service cost/(credit) | | | (788 | ) | | | 583 | | | | 467 | | | | (246 | ) | | | 361 | | | | 289 | | | | (1,130 | ) |
| Recognized net loss | | | 5,757 | | | | 1,977 | | | | 2,715 | | | | 2,133 | | | | 1,164 | | | | 1,425 | | | | 702 | |
| Net other postretirement benefit cost | | $ | 16,420 | | | $ | 15,568 | | | $ | 16,704 | | | $ | 5,238 | | | $ | 5,020 | | | $ | 2,623 | | | $ | 1,714 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit for period | | $ | - | | | $ | (4,571 | ) | | $ | - | | | $ | - | | | $ | - | | | $ | (851 | ) | | $ | - | |
| Net (gain)/loss | | | 38,149 | | | | (88 | ) | | | (3,024 | ) | | | 8,786 | | | | 7,982 | | | | 23,158 | | | | 8,291 | |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of transition obligation | | | (821 | ) | | | (337 | ) | | | (382 | ) | | | (351 | ) | | | (1,661 | ) | | | (265 | ) | | | (8 | ) |
| Amortization of prior service cost/(credit) | | | 788 | | | | (583 | ) | | | (467 | ) | | | 246 | | | | (361 | ) | | | (289 | ) | | | 1,130 | |
| Amortization of net loss | | | (5,757 | ) | | | (1,977 | ) | | | (2,715 | ) | | | (2,133 | ) | | | (1,164 | ) | | | (1,425 | ) | | | (702 | ) |
| Total | | $ | 32,359 | | | $ | (7,556 | ) | | $ | (6,588 | ) | | $ | 6,548 | | | $ | 4,796 | | | $ | 20,328 | | | $ | 8,711 | |
| Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $ | 48,779 | | | $ | 8,012 | | | $ | 10,116 | | | $ | 11,786 | | | $ | 9,816 | | | $ | 22,951 | | | $ | 10,425 | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition (asset)/obligation | | $ | 821 | | | $ | 239 | | | $ | 382 | | | $ | 351 | | | $ | 1,661 | | | $ | 265 | | | $ | 8 | |
| Prior service cost/(credit) | | $ | (788 | ) | | $ | (306 | ) | | $ | 467 | | | $ | (246 | ) | | $ | 361 | | | $ | 76 | | | $ | (1,130 | ) |
| Net loss | | $ | 7,502 | | | $ | 2,322 | | | $ | 2,444 | | | $ | 2,415 | | | $ | 1,297 | | | $ | 2,689 | | | $ | 1,335 | |
2011 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| Other post retirement costs: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $8,053 | | $6,158 | | $6,540 | | $2,632 | | $1,448 | | $3,074 | | $2,642 |
| Interest cost on APBO | | 13,742 | | 8,298 | | 8,767 | | 4,370 | | 3,225 | | 5,945 | | 2,666 |
| Expected return on assets | | (11,528) | | - | | - | | (3,906) | | (3,200) | | (7,496) | | (2,115) |
Amortization of transition obligation | | 821 | | 239 | | 383 | | 352 | | 1,190 | | 187 | | 9 |
Amortization of prior service cost/(credit) | | (530) | | (824) | | (247) | | (139) | | 38 | | (428) | | (589) |
| Recognized net loss | | 6,436 | | 2,896 | | 2,793 | | 2,160 | | 968 | | 2,803 | | 1,477 |
Net other postretirement benefit cost | | $16,994 | | $16,767 | | $18,236 | | $5,469 | | $3,669 | | $4,085 | | $4,090 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Net loss | | $32,241 | | $28,721 | | $24,837 | | $12,598 | | $8,946 | | $23,125 | | $8,499 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of transition obligation | | (821) | | (239) | | (383) | | (352) | | (1,190) | | (187) | | (9) |
Amortization of prior service cost/(credit) | | 530 | | 824 | | 247 | | 139 | | (38) | | 428 | | 589 |
| Amortization of net loss | | (6,436) | | (2,896) | | (2,793) | | (2,160) | | (968) | | (2,803) | | (1,477) |
| Total | | $25,514 | | $26,410 | | $21,908 | | $10,225 | | $6,750 | | $20,563 | | $7,602 |
Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $42,508 | | $43,177 | | $40,144 | | $15,694 | | $10,419 | | $24,648 | | $11,692 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Transition obligation | | $820 | | $238 | | $382 | | $351 | | $1,189 | | $187 | | $8 |
| Prior service cost/(credit) | | ($530) | | ($824) | | ($247) | | ($139) | | $38 | | ($428) | | ($63) |
| Net loss | | $8,365 | | $4,778 | | $4,398 | | $2,926 | | $1,562 | | $4,329 | | $1,994 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2010 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| Other post retirement costs: | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $7,372 | | $5,481 | | $5,483 | | $2,200 | | $1,389 | | $2,789 | | $2,251 |
| Interest cost on APBO | | 14,515 | | 8,574 | | 9,075 | | 4,370 | | 3,598 | | 6,326 | | 2,562 |
| Expected return on assets | | (9,780) | | - | | - | | (3,551) | | (2,899) | | (6,872) | | (1,870) |
Amortization of transition obligation | | 821 | | 238 | | 382 | | 351 | | 1,661 | | 265 | | 8 |
Amortization of prior service cost/(credit) | | (786) | | (306) | | 467 | | (246) | | 361 | | 76 | | (763) |
| Recognized net loss | | 6,758 | | 2,653 | | 2,440 | | 1,903 | | 1,095 | | 3,008 | | 1,301 |
Net other postretirement benefit cost | | $18,900 | | $16,640 | | $17,847 | | $5,027 | | $5,205 | | $5,592 | | $3,489 |
| | | | | | | | | | | | | | | |
Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | |
| Prior service credit for period | | ($5,023) | | ($3,109) | | ($3,204) | | ($1,529) | | ($1,587) | | ($2,871) | | ($519) |
| Net (gain)/loss | | 4,032 | | 6,583 | | 7,734 | | 5,765 | | (478) | | 922 | | 4,067 |
Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | |
Amortization of transition obligation | | (821) | | (238) | | (382) | | (351) | | (1,661) | | (265) | | (8) |
Amortization of prior service cost/(credit) | | 786 | | 306 | | (467) | | 246 | | (361) | | (76) | | 763 |
| Amortization of net loss | | (6,758) | | (2,653) | | (2,440) | | (1,903) | | (1,095) | | (3,008) | | (1,301) |
| Total | | ($7,784) | | $889 | | $1,241 | | $2,228 | | ($5,182) | | ($5,298) | | $3,002 |
Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $11,116 | | $17,529 | | $19,088 | | $7,255 | | $23 | | $294 | | $6,491 |
| | | | | | | | | | | | | | | |
Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | |
| Transition obligation | | $821 | | $239 | | $383 | | $352 | | $1,190 | | $187 | | $9 |
| Prior service cost/(credit) | | ($530) | | ($824) | | ($247) | | ($139) | | $38 | | ($428) | | ($589) |
| Net loss | | $6,436 | | $2,896 | | $2,793 | | $2,160 | | $968 | | $2,803 | | $1,477 |
2007 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | | | | System Energy | |
| | | (In Thousands) | |
| Other post retirement costs: | | | | | | | | | | | | | | | | | | | | | |
Service cost - benefits earned during the period | | $ | 6,099 | | | $ | 6,188 | | | $ | 3,890 | | | $ | 1,904 | | | $ | 1,019 | | | $ | 2,001 | | | $ | 1,804 | |
| Interest cost on APBO | | | 12,147 | | | | 11,504 | | | | 7,764 | | | | 4,195 | | | | 3,480 | | | | 5,041 | | | | 1,732 | |
| Expected return on assets | | | (8,923 | ) | | | (6,787 | ) | | | - | | | | (3,275 | ) | | | (2,729 | ) | | | (6,787 | ) | | | (1,878 | ) |
| Amortization of transition obligation | | | 821 | | | | 604 | | | | 382 | | | | 351 | | | | 1,662 | | | | 266 | | | | 9 | |
| Amortization of prior service cost/(credit) | | | (788 | ) | | | 872 | | | | 467 | | | | (246 | ) | | | 361 | | | | 289 | | | | (1,130 | ) |
| Recognized net loss | | | 6,001 | | | | 3,169 | | | | 3,059 | | | | 2,449 | | | | 1,129 | | | | 1,393 | | | | 591 | |
| Special termination benefits | | | 251 | | | | 79 | | | | 124 | | | | - | | | | - | | | | - | | | | 38 | |
| Net other postretirement benefit cost | | $ | 15,608 | | | $ | 15,629 | | | $ | 15,686 | | | $ | 5,378 | | | $ | 4,922 | | | $ | 2,203 | | | $ | 1,166 | |
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Net (gain)/loss | | $ | 4,045 | | | $ | 7,031 | | | $ | (522 | ) | | $ | (2,046 | ) | | $ | 1,226 | | | $ | 2,913 | | | $ | 2,034 | |
| Amounts reclassified from regulatory asset and/or AOCI to net periodic benefit cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of transition obligation | | | (821 | ) | | | (604 | ) | | | (382 | ) | | | (351 | ) | | | (1,662 | ) | | | (266 | ) | | | (9 | ) |
| Amortization of prior service cost/(credit) | | | 788 | | | | (872 | ) | | | (467 | ) | | | 246 | | | | (361 | ) | | | (289 | ) | | | 1,130 | |
| Amortization of net loss | | | (6,001 | ) | | | (3,169 | ) | | | (3,059 | ) | | | (2,449 | ) | | | (1,129 | ) | | | (1,393 | ) | | | (591 | ) |
| Total | | $ | (1,989 | ) | | $ | 2,386 | | | $ | (4,430 | ) | | $ | (4,600 | ) | | $ | (1,926 | ) | | $ | 965 | | | $ | 2,564 | |
| Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | | $ | 13,619 | | | $ | 18,015 | | | $ | 11,256 | | | $ | 778 | | | $ | 2,996 | | | $ | 3,168 | | | $ | 3,730 | |
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | 821 | | | $ | 338 | | | $ | 382 | | | $ | 351 | | | $ | 1,662 | | | $ | 266 | | | $ | 9 | |
| Prior service cost/(credit) | | $ | (788 | ) | | $ | 583 | | | $ | 467 | | | $ | (246 | ) | | $ | 361 | | | $ | 289 | | | $ | (1,130 | ) |
| Net loss | | $ | 5,759 | | | $ | 1,977 | | | $ | 2,716 | | | $ | 2,133 | | | $ | 1,164 | | | $ | 1,425 | | | $ | 703 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheet of Entergy Corporation and its Subsidiaries as of December 31, 20092012 and 2008
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| Change in APBO | | | | | | |
| Balance at beginning of year | | $ | 1,155,072 | | | $ | 1,129,631 | |
| Service cost | | | 46,765 | | | | 47,198 | |
| Interest cost | | | 75,265 | | | | 71,295 | |
| Plan amendments | | | - | | | | (5,422 | ) |
| Plan participant contributions | | | 17,394 | | | | 8,618 | |
| Actuarial (gain)/loss | | | 59,537 | | | | (33,168 | ) |
| Benefits paid | | | (79,076 | ) | | | (68,799 | ) |
| Medicare Part D subsidy received | | | 5,119 | | | | 5,719 | |
| Balance at end of year | | $ | 1,280,076 | | | $ | 1,155,072 | |
| | | | | | | | | |
| Change in Plan Assets | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 295,908 | | | $ | 350,719 | |
| Actual return on plan assets | | | 58,038 | | | | (64,350 | ) |
| Employer contributions | | | 70,135 | | | | 69,720 | |
| Plan participant contributions | | | 17,394 | | | | 8,618 | |
| Acquisition | | | - | | | | - | |
| Benefits paid | | | (79,076 | ) | | | (68,799 | ) |
| Fair value of assets at end of year | | $ | 362,399 | | | $ | 295,908 | |
| | | | | | | | | |
| Funded status | | $ | (917,677 | ) | | $ | (859,164 | ) |
| | | | | | | | | |
| Amounts recognized in the balance sheet | | | | | | | | |
| Current liabilities | | $ | (31,189 | ) | | $ | (29,594 | ) |
| Non-current liabilities | | | (886,488 | ) | | | (829,570 | ) |
| Total funded status | | $ | (917,677 | ) | | $ | (859,164 | ) |
| | | | | | | | | |
| Amounts recognized as a regulatory asset (before tax) | | | | | | | | |
| Transition obligation | | $ | 9,325 | | | $ | 12,436 | |
| Prior service cost/(credit) | | | 1,877 | | | | (966 | ) |
| Net loss | | | 239,400 | | | | 266,086 | |
| | | $ | 250,602 | | | $ | 277,556 | |
| Amounts recognized as AOCI (before tax) | | | | | | | | |
| Transition obligation | | $ | 1,862 | | | $ | 2,483 | |
| Prior service credit | | | (21,855 | ) | | | (35,108 | ) |
| Net loss | | | 147,563 | | | | 114,864 | |
| | | $ | 127,570 | | | $ | 82,239 | |
| | | December 31, |
| | | 2012 | | 2011 |
| | | (In Thousands) |
| Change in APBO | | | | |
| Balance at beginning of year | | $1,652,369 | | $1,386,370 |
| Service cost | | 68,883 | | 59,340 |
| Interest cost | | 82,561 | | 74,522 |
| Plan amendments | | - | | (29,507) |
| Plan participant contributions | | 18,102 | | 14,650 |
| Actuarial loss | | 102,833 | | 216,549 |
| Benefits paid | | (83,825) | | (77,454) |
| Medicare Part D subsidy received | | 5,999 | | 4,551 |
| Early Retiree Reinsurance Program proceeds | | - | | 3,348 |
| Balance at end of year | | $1,846,922 | | $1,652,369 |
| | | | | |
| Change in Plan Assets | | | | |
| Fair value of assets at beginning of year | | $427,172 | | $404,430 |
| Actual return on plan assets | | 44,752 | | 9,432 |
| Employer contributions | | 82,247 | | 76,114 |
| Plan participant contributions | | 18,102 | | 14,650 |
| Early Retiree Reinsurance Program proceeds | | - | | - |
| Benefits paid | | (83,825) | | (77,454) |
| Fair value of assets at end of year | | $488,448 | | $427,172 |
| | | | | |
| Funded status | | ($1,358,474) | | ($1,225,197) |
| | | | | |
| Amounts recognized in the balance sheet | | | | |
| Current liabilities | | ($33,813) | | ($32,832) |
| Non-current liabilities | | (1,324,661) | | (1,192,365) |
| Total funded status | | ($1,358,474) | | ($1,225,197) |
| | | | | |
| Amounts recognized as a regulatory asset | | | | |
| Transition obligation | | $- | | $2,557 |
| Prior service credit | | (5,307) | | (6,628) |
| Net loss | | 367,519 | | 353,905 |
| | | $362,212 | | $349,834 |
| Amounts recognized as AOCI (before tax) | | | | |
| Transition obligation | | $- | | $620 |
| Prior service credit | | (49,335) | | (66,176) |
| Net loss | | 355,900 | | 313,379 |
| | | $306,565 | | $247,823 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefit Obligations, Plan Assets, Funded Status, and Amounts Not Yet Recognized and Recognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 20092012 and 2008
2009 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | | $ | 231,877 | | | $ | 123,144 | | | $ | 141,579 | | | $ | 72,117 | | | $ | 60,095 | | | $ | 91,926 | | | $ | 36,974 | |
| Service cost | | | 7,058 | | | | 4,783 | | | | 4,589 | | | | 2,119 | | | | 1,242 | | | | 2,475 | | | | 2,051 | |
| Interest cost | | | 15,036 | | | | 8,020 | | | | 9,188 | | | | 4,690 | | | | 3,869 | | | | 5,959 | | | | 2,421 | |
| Plan participant contributions | | | 4,374 | | | | 1,947 | | | | 2,236 | | | | 1,148 | | | | 545 | | | | 1,631 | | | | 637 | |
| Actuarial (gain)/loss | | | 3,529 | | | | 14,746 | | | | 6,080 | | | | (1,321 | ) | | | 300 | | | | 11,226 | | | | 4,599 | |
| Benefits paid | | | (17,602 | ) | | | (8,881 | ) | | | (11,115 | ) | | | (5,450 | ) | | | (5,161 | ) | | | (6,840 | ) | | | (3,803 | ) |
| Medicare Part D subsidy received | | | 1,194 | | | | 679 | | | | 762 | | | | 398 | | | | 421 | | | | 581 | | | | 120 | |
| Balance at end of year | | $ | 245,466 | | | $ | 144,438 | | | $ | 153,319 | | | $ | 73,701 | | | $ | 61,311 | | | $ | 106,958 | | | $ | 42,999 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 102,893 | | | $ | - | | | $ | - | | | $ | 36,711 | | | $ | 40,424 | | | $ | 76,001 | | | $ | 21,657 | |
| Actual return on plan assets | | | 21,463 | | | | - | | | | - | | | | 7,625 | | | | 6,508 | | | | 15,099 | | | | 4,088 | |
| Employer contributions | | | 18,548 | | | | 6,934 | | | | 8,879 | | | | 6,722 | | | | 5,094 | | | | 7,388 | | | | 3,299 | |
| Plan participant contributions | | | 4,374 | | | | 1,947 | | | | 2,236 | | | | 1,148 | | | | 545 | | | | 1,631 | | | | 637 | |
| Benefits paid | | | (17,602 | ) | | | (8,881 | ) | | | (11,115 | ) | | | (5,450 | ) | | | (5,161 | ) | | | (6,840 | ) | | | (3,803 | ) |
| Fair value of assets at end of year | | $ | 129,676 | | | $ | - | | | $ | - | | | $ | 46,756 | | | $ | 47,410 | | | $ | 93,279 | | | $ | 25,878 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded status | | $ | (115,790 | ) | | $ | (144,438 | ) | | $ | (153,319 | ) | | $ | (26,945 | ) | | $ | (13,901 | ) | | $ | (13,679 | ) | | $ | (17,121 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current asset | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Current liabilities | | | - | | | | (7,736 | ) | | | (9,130 | ) | | | - | | | | - | | | | - | | | | - | |
| Non-current liabilities | | | (115,790 | ) | | | (136,702 | ) | | | (144,189 | ) | | | (26,945 | ) | | | (13,901 | ) | | | (13,679 | ) | | | (17,121 | ) |
| Total funded status | | $ | (115,790 | ) | | $ | (144,438 | ) | | $ | (153,319 | ) | | $ | (26,945 | ) | | $ | (13,901 | ) | | $ | (13,679 | ) | | $ | (17,121 | ) |
Amounts recognized in regulatory asset (before tax) | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | 2,462 | | | $ | - | | | $ | - | | | $ | 1,054 | | | $ | 4,983 | | | $ | 795 | | | $ | 25 | |
| Prior service cost | | | 1,031 | | | | - | | | | - | | | | 439 | | | | 1,195 | | | | 226 | | | | (1,142 | ) |
| Net loss | | | 105,644 | | | | - | | | | - | | | | 30,204 | | | | 19,396 | | | | 46,970 | | | | 19,912 | |
| | | $ | 109,137 | | | $ | - | | | $ | - | | | $ | 31,697 | | | $ | 25,574 | | | $ | 47,991 | | | $ | 18,795 | |
Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | - | | | $ | 715 | | | $ | 1,147 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Prior service cost | | | - | | | | (1,532 | ) | | | 2,082 | | | | - | | | | - | | | | - | | | | - | |
| Net loss | | | - | | | | 46,277 | | | | 44,601 | | | | - | | | | - | | | | - | | | | - | |
| | | $ | - | | | $ | 45,460 | | | $ | 47,830 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | |
| Balance at beginning of year | | $290,613 | | $191,877 | | $196,352 | | $94,570 | | $69,316 | | $133,602 | | $60,526 |
| Service cost | | 9,089 | | 7,521 | | 7,796 | | 3,093 | | 1,689 | | 3,651 | | 3,293 |
| Interest cost | | 14,452 | | 9,590 | | 9,781 | | 4,716 | | 3,422 | | 6,650 | | 3,028 |
| Plan participant contributions | | 4,440 | | 1,945 | | 2,725 | | 1,269 | | 742 | | 1,526 | | 820 |
| Actuarial (gain)/loss | | 13,256 | | 5,818 | | 16,215 | | 1,625 | | 3,240 | | 2,645 | | 2,861 |
| Benefits paid | | (17,873) | | (9,543) | | (13,760) | | (5,199) | | (4,605) | | (6,604) | | (2,764) |
| Medicare Part D subsidy received | | 1,331 | | 779 | | 908 | | 434 | | 396 | | 644 | | 170 |
| Balance at end of year | | $315,308 | | $207,987 | | $220,017 | | $100,508 | | $74,200 | | $142,114 | | $67,934 |
| | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | |
Fair value of assets at beginning of year | | $164,846 | | $- | | $- | | $54,452 | | $53,418 | | $105,181 | | $32,012 |
| Actual return on plan assets | | 18,219 | | - | | - | | 5,874 | | 4,691 | | 10,869 | | 3,419 |
| Employer contributions | | 24,386 | | 7,598 | | 11,035 | | 6,555 | | 4,405 | | 4,852 | | 5,987 |
| Plan participant contributions | | 4,440 | | 1,945 | | 2,725 | | 1,269 | | 742 | | 1,526 | | 820 |
| Benefits paid | | (17,873) | | (9,543) | | (13,760) | | (5,199) | | (4,605) | | (6,604) | | (2,764) |
| Fair value of assets at end of year | | $194,018 | | $- | | $- | | $62,951 | | $58,651 | | $115,824 | | $39,474 |
| | | | | | | | | | | | | | | |
| Funded status | | ($121,290) | | ($207,987) | | ($220,017) | | ($37,557) | | ($15,549) | | ($26,290) | | ($28,460) |
| | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | |
| Current liabilities | | $- | | ($7,546) | | ($9,152) | | $- | | $- | | $- | | $- |
| Non-current liabilities | | (121,290) | | (200,441) | | (210,865) | | (37,557) | | (15,549) | | (26,290) | | (28,460) |
| Total funded status | | ($121,290) | | ($207,987) | | ($220,017) | | ($37,557) | | ($15,549) | | ($26,290) | | ($28,460) |
| | | | | | | | | | | | | | | |
Amounts recognized in regulatory asset | | | | | | | | | | | | | | |
| Prior service cost/(credit) | | ($2,146) | | $- | | $- | | ($566) | | $114 | | ($1,709) | | ($246) |
| Net loss | | 129,484 | | - | | - | | 41,855 | | 26,502 | | 61,077 | | 29,773 |
| | | $127,338 | | $- | | $- | | $41,289 | | $26,616 | | $59,368 | | $29,527 |
| | | | | | | | | | | | | | | |
Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | |
| Prior service credit | | $- | | ($2,687) | | ($1,095) | | $- | | $- | | $- | | $- |
| Net loss | | - | | 77,113 | | 83,795 | | - | | - | | - | | - |
| | | $- | | $74,426 | | $82,700 | | $- | | $- | | $- | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2011 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | |
| Balance at beginning of year | | $256,859 | | $154,466 | | $163,720 | | $81,464 | | $60,735 | | $111,106 | | $49,501 |
| Service cost | | 8,053 | | 6,158 | | 6,540 | | 2,632 | | 1,448 | | 3,074 | | 2,642 |
| Interest cost | | 13,742 | | 8,298 | | 8,767 | | 4,370 | | 3,225 | | 5,945 | | 2,666 |
| Plan participant contributions | | 3,680 | | 1,525 | | 2,218 | | 994 | | 615 | | 1,222 | | 687 |
| Actuarial (gain)/loss | | 23,394 | | 28,721 | | 24,837 | | 9,695 | | 7,974 | | 17,994 | | 7,144 |
| Benefits paid | | (16,850) | | (8,359) | | (10,883) | | (4,986) | | (5,074) | | (6,326) | | (2,513) |
| Medicare Part D subsidy received | | 1,025 | | 585 | | 683 | | 336 | | 358 | | 489 | | 116 |
Early Retiree Reinsurance Program Proceeds | | 710 | | 483 | | 470 | | 65 | | 35 | | 98 | | 283 |
| Balance at end of year | | $290,613 | | $191,877 | | $196,352 | | $94,570 | | $69,316 | | $133,602 | | $60,526 |
| | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | |
Fair value of assets at beginning of year | | $148,622 | | $- | | $- | | $52,064 | | $52,005 | | $103,214 | | $29,347 |
| Actual return on plan assets | | 2,681 | | - | | - | | 1,003 | | 2,228 | | 2,365 | | 760 |
| Employer contributions | | 26,713 | | 6,834 | | 8,665 | | 5,377 | | 3,644 | | 4,706 | | 3,731 |
| Plan participant contributions | | 3,680 | | 1,525 | | 2,218 | | 994 | | 615 | | 1,222 | | 687 |
| Benefits paid | | (16,850) | | (8,359) | | (10,883) | | (4,986) | | (5,074) | | (6,326) | | (2,513) |
| Fair value of assets at end of year | | $164,846 | | $- | | $- | | $54,452 | | $53,418 | | $105,181 | | $32,012 |
| | | | | | | | | | | | | | | |
| Funded status | | ($125,767) | | ($191,877) | | ($196,352) | | ($40,118) | | ($15,898) | | ($28,421) | | ($28,514) |
| | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | |
| Current liabilities | | $- | | ($7,651) | | ($9,143) | | $- | | $- | | $- | | $- |
| Non-current liabilities | | (125,767) | | (184,226) | | (187,209) | | (40,118) | | (15,898) | | (28,421) | | (28,514) |
| Total funded status | | ($125,767) | | ($191,877) | | ($196,352) | | ($40,118) | | ($15,898) | | ($28,421) | | ($28,514) |
| | | | | | | | | | | | | | | |
Amounts recognized in regulatory asset | | | | | | | | | | | | | | |
| Transition obligation | | $820 | | $- | | $- | | $351 | | $1,189 | | $187 | | $8 |
| Prior service cost/(credit) | | (2,676) | | - | | - | | (705) | | 152 | | (2,137) | | (309) |
| Net loss | | 128,723 | | - | | - | | 44,504 | | 25,801 | | 65,206 | | 29,700 |
| | | $126,867 | | $- | | $- | | $44,150 | | $27,142 | | $63,256 | | $29,399 |
| | | | | | | | | | | | | | | |
Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | |
| Transition obligation | | $- | | $238 | | $382 | | $- | | $- | | $- | | $- |
| Prior service credit | | - | | (3,511) | | (1,342) | | - | | - | | - | | - |
| Net loss | | - | | 76,032 | | 71,939 | | - | | - | | - | | - |
| | | $- | | $72,759 | | $70,979 | | $- | | $- | | $- | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2008 | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | (In Thousands) | |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | | $ | 218,817 | | | $ | 121,241 | | | $ | 138,932 | | | $ | 72,382 | | | $ | 60,948 | | | $ | 91,603 | | | $ | 33,378 | |
| Service cost | | | 6,824 | | | | 5,003 | | | | 4,394 | | | | 2,057 | | | | 1,179 | | | | 2,423 | | | | 2,053 | |
| Interest cost | | | 13,772 | | | | 7,668 | | | | 8,746 | | | | 4,563 | | | | 3,810 | | | | 5,759 | | | | 2,124 | |
| Amendment | | | - | | | | (4,571 | ) | | | - | | | | - | | | | - | | | | (851 | ) | | | - | |
| Plan participant contributions | | | 1,944 | | | | 875 | | | | 1,139 | | | | 630 | | | | 207 | | | | 981 | | | | 249 | |
| Actuarial (gain)/loss | | | 5,094 | | | | (88 | ) | | | (3,024 | ) | | | (3,288 | ) | | | (1,744 | ) | | | (1,843 | ) | | | 1,796 | |
| Benefits paid | | | (15,940 | ) | | | (7,698 | ) | | | (9,485 | ) | | | (4,695 | ) | | | (4,814 | ) | | | (6,855 | ) | | | (2,747 | ) |
| Medicare Part D subsidy received | | | 1,366 | | | | 714 | | | | 877 | | | | 468 | | | | 509 | | | | 709 | | | | 121 | |
| Balance at end of year | | $ | 231,877 | | | $ | 123,144 | | | $ | 141,579 | | | $ | 72,117 | | | $ | 60,095 | | | $ | 91,926 | | | $ | 36,974 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | | $ | 117,916 | | | $ | - | | | $ | - | | | $ | 43,502 | | | $ | 45,737 | | | $ | 92,024 | | | $ | 26,731 | |
| Actual return on plan assets | | | (23,089 | ) | | | - | | | | - | | | | (8,454 | ) | | | (6,571 | ) | | | (17,463 | ) | | | (4,452 | ) |
| Employer contributions | | | 22,062 | | | | 6,823 | | | | 8,346 | | | | 5,728 | | | | 5,865 | | | | 7,314 | | | | 1,876 | |
| Plan participant contributions | | | 1,944 | | | | 875 | | | | 1,139 | | | | 630 | | | | 207 | | | | 981 | | | | 249 | |
| Benefits paid | | | (15,940 | ) | | | (7,698 | ) | | | (9,485 | ) | | | (4,695 | ) | | | (4,814 | ) | | | (6,855 | ) | | | (2,747 | ) |
| Fair value of assets at end of year | | $ | 102,893 | | | $ | - | | | $ | - | | | $ | 36,711 | | | $ | 40,424 | | | $ | 76,001 | | | $ | 21,657 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Funded status | | $ | (128,984 | ) | | $ | (123,144 | ) | | $ | (141,579 | ) | | $ | (35,406 | ) | | $ | (19,671 | ) | | $ | (15,925 | ) | | $ | (15,317 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current asset | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Current liabilities | | | - | | | | (6,895 | ) | | | (8,912 | ) | | | - | | | | - | | | | - | | | | - | |
| Non-current liabilities | | | (128,984 | ) | | | (116,249 | ) | | | (132,667 | ) | | | (35,406 | ) | | | (19,671 | ) | | | (15,925 | ) | | | (15,317 | ) |
| Total funded status | | $ | (128,984 | ) | | $ | (123,144 | ) | | $ | (141,579 | ) | | $ | (35,406 | ) | | $ | (19,671 | ) | | $ | (15,925 | ) | | $ | (15,317 | ) |
Amounts recognized in regulatory asset (before tax) | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | 3,283 | | | $ | - | | | $ | - | | | $ | 1,406 | | | $ | 6,645 | | | $ | 1,060 | | | $ | 34 | |
| Prior service cost | | | 243 | | | | - | | | | - | | | | 193 | | | | 1,556 | | | | 302 | | | | (2,122 | ) |
| Net loss | | | 123,355 | | | | - | | | | - | | | | 38,752 | | | | 24,392 | | | | 47,815 | | | | 19,023 | |
| | | $ | 126,881 | | | $ | - | | | $ | - | | | $ | 40,351 | | | $ | 32,593 | | | $ | 49,177 | | | $ | 16,935 | |
Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Transition obligation | | $ | - | | | $ | 954 | | | $ | 1,529 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
| Prior service cost | | | - | | | | (1,838 | ) | | | 2,549 | | | | - | | | | - | | | | - | | | | - | |
| Net loss | | | - | | | | 33,506 | | | | 40,736 | | | | - | | | | - | | | | - | | | | - | |
| | | $ | - | | | $ | 32,622 | | | $ | 44,814 | | | $ | - | | | $ | - | | | $ | - | | | $ | - | |
Entergy’s non-qualified, non-current pension liability at December 31, 2012 and 2011 was $137.2 million and $153.2 million, respectively; and its current liability was $62.1 million and $11.2 million, respectively. The unamortized transition asset, prior service cost and net loss are recognized in regulatory assets ($81.2 million at December 31, 2012 and $58.9 million at December 31, 2011) and accumulated other comprehensive income before taxes ($32.5 million at December 31, 2012 and $27.2 million at December 31, 2011).
The Registrant Subsidiaries (except System Energy) participate in Entergy’s non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for the non-qualified plans for 2012, 2011, and 2010, was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2012 | | $464 | | $158 | | $12 | | $183 | | $79 | | $648 |
| 2011 | | $498 | | $167 | | $14 | | $190 | | $65 | | $763 |
| 2010 | | $501 | | $162 | | $102 | | $206 | | $26 | | $683 |
Included in the 2012 net periodic pension cost above are settlement charges of $38 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan. Included in the 2011 net periodic pension cost above are settlement charges of $41 thousand for Entergy Arkansas related to the lump sum benefits paid out of the plan. Included in the 2010 net periodic pension cost above are settlement charges of $86 thousand for Entergy Arkansas, $80 thousand for Entergy Louisiana, and $5 thousand for Entergy Texas related to the lump sum benefits paid out of the plan.
The projected benefit obligation for the non-qualified plans as of December 31, 2012 and 2011 was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2012 | | $4,323 | | $2,909 | | $116 | | $1,841 | | $457 | | $9,732 |
| 2011 | | $4,153 | | $2,781 | | $118 | | $1,682 | | $376 | | $10,103 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The accumulated benefit obligation for the non-qualified plans as of December 31, 2012 and 2011 was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2012 | | $3,856 | | $2,899 | | $116 | | $1,590 | | $427 | | $9,127 |
| 2011 | | $3,755 | | $2,768 | | $118 | | $1,460 | | $345 | | $10,030 |
The following amounts were recorded on the balance sheet as of December 31, 2012 and 2011:
2012 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| Current liabilities | | ($209) | | ($257) | | ($17) | | ($118) | | ($25) | | ($853) |
| Non-current liabilities | | (4,114) | | (2,652) | | (99) | | (1,723) | | (432) | | (8,879) |
| Total Funded Status | | ($4,323) | | ($2,909) | | ($116) | | ($1,841) | | ($457) | | ($9,732) |
| | | | | | | | | | | | | |
| Regulatory Asset | | $2,359 | | $679 | | ($29) | | $800 | | $88 | | ($465) |
Accumulated other comprehensive income (before taxes) | | $- | | $102 | | $- | | $- | | $- | | $- |
2011 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| Current liabilities | | ($272) | | ($260) | | ($18) | | ($114) | | ($25) | | ($1,029) |
| Non-current liabilities | | (3,881) | | (2,521) | | (100) | | (1,568) | | (351) | | (9,074) |
| Total Funded Status | | ($4,153) | | ($2,781) | | ($118) | | ($1,682) | | ($376) | | ($10,103) |
| | | | | | | | | | | | | |
| Regulatory Asset | | $2,385 | | $445 | | ($36) | | $703 | | $78 | | ($292) |
Accumulated other comprehensive income (before taxes) | | $- | | $104 | | $- | | $- | | $- | | $- |
Accounting for Pension and Other Postretirement Benefits
Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. This is measured as the difference between plan assets at fair value and the benefit obligation. Entergy uses a December 31 measurement date for its pension and other postretirement plans. Employers are to record previously unrecognized gains and losses, prior service costs, and any remaining transition asset or obligation (that resulted from adopting prior pension and other postretirement benefits accounting standards) as comprehensive income and/or as a regulatory asset reflective of the recovery mechanism for pension and other postretirement benefit costs in the Registrant Subsidiaries’ respective regulatory jurisdictions. For the portion of
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Gulf States Louisiana that is not regulated, the unrecognized prior service cost, gains and losses, and transition asset/obligation for its pension and other postretirement benefit obligations are recorded as other comprehensive income. Entergy Gulf States Louisiana and Entergy Louisiana recover other postretirement benefit costs on a pay as you go basis and record the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also requires that changes in the funded status be recorded as other comprehensive income and/or a regulatory asset in the period in which the changes occur.
With regard to pension and other postretirement costs, Entergy calculates the expected return on pension and other postretirement benefit plan assets by multiplying the long-term expected rate of return on assets by the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.
Qualified Pension and Other Postretirement Plans'Plans’ Assets
Entergy's qualified pension and postretirement plans' weighted-average asset allocations by asset category at December 31, 2009 and 2008 are as follows:
| | Qualified Pension | | Postretirement |
| Actual Asset Allocation | 2009 | | 2008 | | 2009 | 2008 |
| | | | | | Non-Taxable | Taxable | Non-Taxable | Taxable |
| Domestic Equity Securities | 46% | | 43% | | 40% | 36% | 37% | 37% |
| International Equity Securities | 21% | | 19% | | 19% | 0% | 17% | 0% |
| Fixed Income Securities | 32% | | 36% | | 41% | 63% | 46% | 63% |
| Other | 1% | | 2% | | 0% | 1% | 0% | 0% |
The Plan Administrator'sAdministrator’s trust asset investment strategy is to invest the assets in a manner whereby longlong- term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.
In the optimization study,studies, the Plan Administrator formulates assumptions about characteristics, such as expected asset class investment returns, volatility (risk), and correlation coefficients among the various asset classes. The future market assumptions used in the optimization study are determined by examining historical market characteristics of the various asset classes, and making adjustments to reflect future conditions expected to prevail over the study period.
The optimization analysis utilized in the Plan Administrator's latest study produced the following approved Target asset class target allocations.
| Target Asset Allocation | Pension | | Postretirement |
| | | | Non-Taxable | Taxable |
| Domestic Equity Securities | 45% | | 38% | 35% |
| International Equity Securities | 20% | | 17% | 0% |
| Fixed Income Securities | 35% | | 45% | 65% |
The expected long term rate of return of 8.5% for 2010 and 2009 for the qualified retirement plans assets isallocations adjust dynamically based on the expected long term return of each asset class, weighted by the target allocation for each class as defined in the table above. The source for each asset class’ expected long term rate of return is the geometric meanfunded status of the respective asset class’ historical total return.pension plans. The time period reflected in the total returns is a long dated period spanning several decades.
The expected long term rate of return of 7.75% for 2010 (8.5% for 2009) for the non-taxable postretirement trust assets is based on the expected long term return of each asset class, weighted by the target allocation for each class as defined in the table above. The source for each asset class’ expected long term rate of return is the geometric mean of the respective asset class’ historical total return. The time period reflected in the total returns is a long dated period spanning several decades.
For the taxable postretirement trust assets the investment allocation includes a high percentage of tax-exempt fixed income securities. The tax-exempt fixed income long term total return was estimated using historical total return data from the 2009 Economic Report of the President. The time period reflected in the tax-exempt fixed income total return is 1940 to 2008. After reflecting the tax-exempt fixed income percentagefollowing targets and unrelated business income tax, the long term rate of return for taxable postretirement trust assets is expected to be 5.5% for 2010 (6% for 2009) annually.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Since precise allocation targets are inefficient to manage security investments, the following ranges were established to produce an acceptable, economically efficient plan to manage around the targets:targets. The target asset allocation range below for pension shows the ranges within which the allocation may adjust based on funded status, with the expectation that the allocation to fixed income securities will increase as the pension funded status increases. The target and range asset allocation for postretirement assets reflects changes made in 2012 as recommended in the latest optimization study
| Pension | | Postretirement |
| | | Non-Taxable | Taxable |
Domestic Equity Securities | 35% to 55% | | 33% to 43% | 30% to 40% |
International Equity Securities | 15% to 25% | | 12% to 22% | 0% |
Total Equity
| 60% to 70% | | 50% to 60% | 30% to 40% |
Fixed Income Securities | 25% to 35% | | 40% to 50% | 60% to 70% |
Other | 0% to 10% | | 0% to 5% | 0% to 5% |
Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 2012 and 2011 and the target asset allocation and ranges are as follows:
Pension Asset Allocation | | Target | Range | Actual 2012 | Actual 2011 |
| | | | | | |
| Domestic Equity Securities | | 45% | 34% to 53% | 44% | 44% |
| International Equity Securities | | 20% | 16% to 24% | 20% | 18% |
| Fixed Income Securities | | 35% | 31% to 41% | 35% | 37% |
| Other | | 0% | 0% to 10% | 1% | 1% |
Postretirement Asset Allocation | Non-Taxable | | Taxable |
| | Target | Range | 2012 | 2011 | | Target | Range | 2012 | 2011 |
| Domestic Equity Securities | 39% | 34% to 44% | 38% | 39% | | 39% | 34% to 44% | 39% | 35% |
| International Equity Securities | 26% | 21% to 31% | 28% | 15% | | 26% | 21% to 31% | 27% | 0% |
| Fixed Income Securities | 35% | 30% to 40% | 34% | 46% | | 35% | 30% to 40% | 34% | 64% |
| Other | 0% | 0% to 5% | 0% | 0% | | 0% | 0% to 5% | 0% | 1% |
In determining its expected long-term rate of return on plan assets used in the calculation of benefit plan costs, Entergy reviews past performance, current and expected future asset allocations, and capital market assumptions of its investment consultant and investment managers.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The expected long-term rate of return for the qualified pension plans’ assets is based primarily on the geometric average of the historical annual performance of a representative portfolio weighted by the target asset allocation defined in the table above, along with other indications of expected return on current assets and expected return available for reinvestment. The time period reflected is a long dated period spanning several decades.
The expected long-term rate of return for the non-taxable postretirement trust assets is determined using the same methodology described above for pension assets, but the asset allocation specific to the non-taxable postretirement assets is used.
For the taxable postretirement trust assets, the investment allocation includes tax-exempt fixed income securities. This asset allocation in combination with the same methodology employed to determine the expected return for other trust assets (as described above), with a modification to reflect applicable taxes, is used to produce the expected long-term rate of return for taxable postretirement trust assets.
Concentrations of Credit Risk
Entergy’s investment guidelines mandate the avoidance of risk concentrations. Types of concentrations specified to be avoided include, but are not limited to, investment concentrations in a single entity, type of industry, foreign country, geographic area and individual security issuance. As of December 31, 20092012 all investment managers and assets were materially in compliance with the approved investment guidelines, therefore there were no significant concentrations (defined as greater than 10 percent of plan assets) of risk in Entergy’s pension and other postretirement benefit plan assets.
The Plan Administrator’s trust asset investment strategy is to invest the assets in a manner whereby long- term earnings on the assets (plus cash contributions) provide adequate funding for retiree benefit payments. The mix of assets is based on an optimization study that identifies asset allocation targets in order to achieve the maximum return for an acceptable level of risk, while minimizing the expected contributions and pension and postretirement expense.
Fair Value Measurements
For fiscal years ending after December 31, 2009,Accounting standards provide the framework for measuring fair value. That framework provides a fair value measurements and disclosures for plan assets are required.
Fair value of a financial instrument ishierarchy that prioritizes the amount that would be receivedinputs to sell an asset or paidvaluation techniques used to transfer a liability in an orderly transaction between market participants at the measurement date. Interest bearing cash, treasury notes and bonds, and common stocks are stated at fair value determined by quoted market prices. Fixed income securities (corporate, government, and securitized), are stated at fair value as determined by broker quotes. Common collective investment trust funds and registered investment company trust funds are stated at estimated fair value based on the fair market value of the underlying investments. The unallocated insurance contract investments are recorded at contract value, which approximatesmeasure fair value. The contract value represents contributions made underhierarchy gives the contract, plus interest, less funds usedhighest priority to pay benefitsunadjusted quoted prices in active markets for identical assets or liabilities (level 1 measurements) and contract expenses, and less distributionsthe lowest priority to the Master Trust. The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes.unobservable inputs (level 3 measurements).
The classificationthree levels forof the fair value hierarchy are as follows:described below:
| · | Level 1 - Level 1 inputs are unadjusted quoted prices for identical assets or liabilities in active markets that the Plan has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. |
| · | Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by an independent party that uses inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden if it is believed such would be more reflective of fair value. Level 2 inputs include the following: |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
- quoted prices for similar assets or liabilities in active markets;
- quoted prices for identical assets or liabilities in inactive markets;
- inputs other than quoted prices that are observable for the asset or liability; or
- inputs that are derived principally from or corroborated by observable market data by correlation or other means.
If an asset or liability has a specified (contractual) term, the Level 2 input must be observable for substantially the full term of the asset or liability.
| · | Level 3 - Level 3 refers to securities valued based on significant unobservable inputs. |
Assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The following tables set forth by level within the fair value hierarchy, a summary of the investments held for the qualified pension and other postretirement plans measured at fair value on a recurring basis at December 31, 2009.2012, and December 31, 2011, a summary of the investments held in the master trusts for Entergy’s qualified pension and other postretirement plans in which the Registrant Subsidiaries participate.
Qualified Pension Trust
(In Thousands)
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Corporate stocks: | | | | | | | | |
| Preferred | | $861 | (b) | $5,906 | (a) | $- | | $6,767 |
| Common | | 787,132 | (b) | - | | - | | 787,132 |
| Common collective trusts | | - | | 1,620,315 | (c) | - | | 1,620,315 |
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | 161,593 | (b) | 150,068 | (a) | - | | 311,661 |
| Corporate debt instruments: | | - | | 429,813 | (a) | - | | 429,813 |
Registered investment companies | | 50,029 | (d) | 483,509 | (e) | - | | 533,538 |
| Other | | - | | 111,001 | (f) | - | | 111,001 |
| Other: | | | | | | | | |
Insurance company general account (unallocated contracts) | | - | | 36,252 | (g) | - | | 36,252 |
| Total investments | | $999,615 | | $2,836,864 | | $- | | $3,836,479 |
| | | | | | | | | |
| Cash | | | | | | | | 571 |
| Other pending transactions | | | | | | | | 4,594 |
Less: Other postretirement assets included in total investments | | | | | | | | (8,784) |
Total fair value of qualified pension assets | | | | | | | | $3,832,860 |
| | Level 1 | | Level 2 | | Level 3 | | Total |
| Equity securities: | | | | | | | |
| Corporate stocks: | | | | | | | |
| Preferred | $- | | $5,318 | | $- | | $5,318 |
| Common | 1,336,454 | | | | - | | 1,336,454 |
| Common collective trusts | - | | 431,703 | | - | | 431,703 |
| Fixed securities: | | | | | | | |
| U.S. Government securities | 60,048 | | 100,025 | | - | | 160,073 |
Corporate debt instruments: | | | | | | | |
| Preferred | - | | 164,448 | | - | | 164,448 |
| All others | - | | 202,377 | | - | | 202,377 |
Registered investment companies | - | | 264,643 | | - | | 264,643 |
| - | | 6,084 | | - | | 6,084 |
| | | | | | | | |
| Other: | | | | | | | |
| Insurance company general account (unallocated contracts) | | | | | | | |
| | | | | | | | |
| Total investments | $1,396,502 | | $1,207,020 | | $- | | $2,603,522 |
| Cash | | | | | | | 1,382 |
| Interest receivable | | | | | | | 6,422 |
| Other pending transactions | | | | | | | (1,716) |
| Less: Other postretirement assets included in total investments | | | | | | | |
| Total fair value of qualified pension assets | | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Corporate stocks: | | | | | | | | |
| Preferred | | $3,738 | (b) | $8,014 | (a) | $- | | $11,752 |
| Common | | 1,010,491 | (b) | - | | - | | 1,010,491 |
| Common collective trusts | | - | | 1,074,178 | (c) | - | | 1,074,178 |
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | 142,509 | (b) | 157,737 | (a) | - | | 300,246 |
| Corporate debt instruments: | | - | | 380,558 | (a) | - | | 380,558 |
Registered investment companies | | 53,323 | (d) | 444,275 | (e) | - | | 497,598 |
| Other | | - | | 101,674 | (f) | - | | 101,674 |
| Other: | | | | | | | | |
Insurance company general account (unallocated contracts) | | - | | 34,696 | (g) | - | | 34,696 |
| Total investments | | $1,210,061 | | $2,201,132 | | $- | | $3,411,193 |
| | | | | | | | | |
| Cash | | | | | | | | 75 |
| Other pending transactions | | | | | | | | (9,238) |
Less: Other postretirement assets included in total investments | | | | | | | | (2,114) |
Total fair value of qualified pension assets | | | | | | | | $3,399,916 |
Other Postretirement Trusts
(In Thousands)
| | | Level 1 | | | Level 2 | | | Level 3 | | | Total | |
| | | | |
| Equity securities: | | | | | | | | | | | | |
| Corporate common stocks | | $ | 50,698 | | | $ | - | | | $ | - | | | $ | 50,698 | |
| Common collective trust | | | - | | | | 140,096 | | | | - | | | | 140,096 | |
| | | | | | | | | | | | | | | | | |
| Fixed securities: | | | | | | | | | | | | | | | | |
| Interest-bearing cash | | | 6,115 | | | | - | | | | - | | | | 6,115 | |
| U.S. Government securities | | | 25,487 | | | | 50,714 | | | | - | | | | 76,201 | |
| Corporate debt instruments | | | - | | | | 35,099 | | | | - | | | | 35,099 | |
| State and local obligations | | | - | | | | 53,443 | | | | - | | | | 53,443 | |
| Total investments | | $ | 82,300 | | | $ | 279,352 | | | $ | - | | | $ | 361,652 | |
| Interest receivable | | | | | | | | | | | | | | | 1,567 | |
| Other pending transactions | | | | | | | | | | | | | | | (3,156 | ) |
| Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | | | | | | | | 2,336 | |
| Total fair value of other postretirement assets | | $ | 82,300 | | | $ | 279,352 | | | $ | - | | | $ | 362,399 | |
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Common collective trust | | $- | | $314,478 | (c) | $- | | $314,478 |
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | 36,392 | (b) | 43,398 | (a) | - | | 79,790 |
| Corporate debt instruments | | - | | 42,163 | (a) | - | | 42,163 |
Registered investment companies | | 3,229 | (d) | - | | - | | 3,229 |
| Other | | - | | 39,846 | (f) | - | | 39,846 |
| Total investments | | $39,621 | | $439,885 | | $- | | $479,506 |
| | | | | | | | | |
| Other pending transactions | | | | | | | | 158 |
Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 8,784 |
Total fair value of other postretirement assets | | | | | | | | $488,448 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2011 | �� | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) |
| Equity securities: | | | | | | | | |
| Common collective trust | | $- | | $208,812 | (c) | $- | | $208,812 |
| Fixed income securities: | | | | | | | | |
| U.S. Government securities | | 42,577 | (b) | 57,151 | (a) | - | | 99,728 |
| Corporate debt instruments | | - | | 42,807 | (a) | - | | 42,807 |
Registered investment companies | | 4,659 | (d) | - | | - | | 4,659 |
| Other | | - | | 69,287 | (f) | - | | 69,287 |
| Total investments | | $47,236 | | $378,057 | | $- | | $425,293 |
| | | | | | | | | |
| Other pending transactions | | | | | | | | (235) |
Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 2,114 |
Total fair value of other postretirement assets | | | | | | | | $427,172 |
| (a) | Certain preferred stocks and fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes. |
| (b) | Common stocks, treasury notes and bonds, and certain preferred stocks and fixed income debt securities are stated at fair value determined by quoted market prices. |
| (c) | The common collective trusts hold investments in accordance with stated objectives. The investment strategy of the trusts is to capture the growth potential of equity markets by replicating the performance of a specified index. Net asset value per share of the common collective trusts estimate fair value. |
| (d) | The registered investment company is a money market mutual fund with a stable net asset value of one dollar per share. |
| (e) | The registered investment company holds investments in domestic and international bond markets and estimates fair value using net asset value per share. |
| (f) | The other remaining assets are U.S. municipal and foreign government bonds stated at fair value as determined by broker quotes. |
| (g) | The unallocated insurance contract investments are recorded at contract value, which approximates fair value. The contract value represents contributions made under the contract, plus interest, less funds used to pay benefits and contract expenses, and less distributions to the master trust. |
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy'sEntergy’s qualified pension plans was $3.4$5.4 billion and $2.9$4.6 billion at December 31, 20092012 and 2008,2011, respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries as of December 31, 20092012 and 20082011 was as follows:
| | | December 31, | | December 31, |
| | | 2009 | | 2008 | | 2012 | | 2011 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| Entergy Arkansas | | $753,029 | | $650,540 | | $1,161,448 | | $1,013,605 |
| Entergy Gulf States Louisiana | | $369,092 | | $288,293 | | $559,190 | | $459,037 |
| Entergy Louisiana | | $435,725 | | $382,821 | | $735,376 | | $632,759 |
| Entergy Mississippi | | $235,988 | | $205,859 | | $336,099 | | $296,259 |
| Entergy New Orleans | | $91,345 | | $80,365 | | $157,233 | | $136,390 |
| Entergy Texas | | $248,919 | | $220,285 | | $350,351 | | $308,628 |
| System Energy | | $132,072 | | $109,839 | | $251,378 | | $227,617 |
Estimated Future Benefit Payments
Based upon the assumptions used to measure Entergy'sEntergy’s qualified pension and other postretirement benefit obligationobligations at December 31, 2009,2012, and including pension and other postretirement benefits attributable to estimated future employee service, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for Entergy Corporation and its subsidiaries will be as follows:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | Estimated Future Benefits Payments | | |
| | | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts |
| | | (In Thousands) |
| Year(s) | | | | | | | | |
| 2010 | | $157,279 | | $23,842 | | $71,439 | | $5,596 |
| 2011 | | $162,897 | | $9,561 | | $75,386 | | $6,108 |
| 2012 | | $172,636 | | $8,259 | | $79,388 | | $7,008 |
| 2013 | | $183,210 | | $15,417 | | $83,440 | | $7,833 |
| 2014 | | $196,157 | | $12,983 | | $87,773 | | $8,676 |
| 2015 - 2019 | | $1,244,961 | | $73,554 | | $510,913 | | $57,300 |
| | | Estimated Future Benefits Payments | | |
| | | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts |
| | | (In Thousands) |
| Year(s) | | | | | | | | |
| 2013 | | $195,907 | | $62,087 | | $74,981 | | $7,875 |
| 2014 | | $209,807 | | $12,440 | | $79,073 | | $8,641 |
| 2015 | | $224,922 | | $13,412 | | $83,788 | | $9,476 |
| 2016 | | $242,186 | | $10,174 | | $88,458 | | $10,358 |
| 2017 | | $261,448 | | $12,248 | | $94,340 | | $11,314 |
| 2018 - 2022 | | $1,648,774 | | $67,055 | | $566,249 | | $72,926 |
Based upon the same assumptions, Entergy expects that benefits to be paid and the Medicare Part D subsidies to be received over the next ten years for the Registrant Subsidiaries will be as follows:
Estimated Future Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| 2010 | | $43,155 | | $16,080 | | $25,221 | | $13,723 | | $4,610 | | $14,811 | | $4,586 | |
| 2011 | | $43,163 | | $16,473 | | $25,343 | | $14,138 | | $4,722 | | $14,920 | | $4,802 | |
| 2012 | | $44,158 | | $17,379 | | $25,590 | | $14,736 | | $4,911 | | $15,449 | | $4,993 | |
| 2013 | | $45,188 | | $18,158 | | $26,295 | | $15,326 | | $5,135 | | $15,946 | | $5,326 | | $53,108 | | $19,664 | | $31,021 | | $15,356 | | $5,906 | | $16,341 | | $8,067 |
| 2014 | | $46,702 | | $19,192 | | $27,181 | | $16,081 | | $5,317 | | $16,323 | | $5,812 | | $54,438 | | $20,964 | | $32,216 | | $16,248 | | $6,221 | | $17,067 | | $8,571 |
| 2015 - 2019 | | $271,057 | | $119,905 | | $154,677 | | $90,907 | | $31,870 | | $89,434 | | $39,901 | |
| 2015 | | | $56,495 | | $22,611 | | $33,392 | | $17,148 | | $6,660 | | $17,906 | | $9,083 |
| 2016 | | | $58,770 | | $24,361 | | $34,867 | | $18,170 | | $7,125 | | $18,777 | | $9,772 |
| 2017 | | | $61,203 | | $26,293 | | $36,648 | | $19,171 | | $7,691 | | $19,778 | | $10,393 |
| 2018 - 2022 | | | $357,927 | | $166,599 | | $216,903 | | $110,145 | | $48,039 | | $114,345 | | $70,026 |
Estimated Future Non-Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | |
| | | (In Thousands) | |
| Year(s) | | | | | | | | | | | | | |
| 2010 | | $341 | | $285 | | $23 | | $107 | | $16 | | $935 | |
| 2011 | | $204 | | $280 | | $22 | | $104 | | $16 | | $1,225 | |
| 2012 | | $207 | | $276 | | $20 | | $100 | | $16 | | $924 | |
| 2013 | | $198 | | $269 | | $19 | | $106 | | $16 | | $904 | |
| 2014 | | $287 | | $274 | | $21 | | $97 | | $16 | | $1,659 | |
| 2015 - 2019 | | $1,215 | | $1,469 | | $76 | | $428 | | $94 | | $3,242 | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Estimated Future Non-Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2013 | | $208 | | $257 | | $18 | | $118 | | $25 | | $853 |
| 2014 | | $357 | | $267 | | $16 | | $114 | | $24 | | $789 |
| 2015 | | $335 | | $247 | | $15 | | $110 | | $24 | | $756 |
| 2016 | | $289 | | $239 | | $13 | | $103 | | $23 | | $891 |
| 2017 | | $288 | | $284 | | $12 | | $100 | | $23 | | $766 |
| 2018 - 2022 | | $1,846 | | $1,004 | | $41 | | $601 | | $196 | | $3,304 |
Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2010 | | $16,456 | | $8,373 | | $9,941 | | $4,649 | | $5,166 | | $7,126 | | $2,071 |
| 2011 | | $17,122 | | $8,796 | | $10,281 | | $4,931 | | $5,274 | | $7,416 | | $2,255 |
| 2012 | | $17,645 | | $9,225 | | $10,632 | | $5,209 | | $5,321 | | $7,693 | | $2,413 |
| 2013 | | $18,147 | | $9,670 | | $10,995 | | $5,484 | | $5,349 | | $7,900 | | $2,565 |
| 2014 | | $18,640 | | $10,131 | | $11,395 | | $5,778 | | $5,403 | | $8,104 | | $2,714 |
| 2015 - 2019 | | $101,690 | | $57,903 | | $63,242 | | $33,267 | | $27,854 | | $44,634 | | $15,911 |
Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2013 | | $16,034 | | $8,381 | | $10,174 | | $4,624 | | $4,859 | | $6,942 | | $2,423 |
| 2014 | | $16,442 | | $8,867 | | $10,588 | | $4,901 | | $4,937 | | $7,218 | | $2,563 |
| 2015 | | $17,094 | | $9,499 | | $10,980 | | $5,194 | | $5,025 | | $7,536 | | $2,755 |
| 2016 | | $17,650 | | $10,087 | | $11,440 | | $5,482 | | $5,097 | | $7,894 | | $2,894 |
| 2017 | | $18,334 | | $10,745 | | $11,978 | | $5,811 | | $5,196 | | $8,331 | | $3,136 |
| 2018 - 2022 | | $101,723 | | $64,193 | | $69,660 | | $33,712 | | $26,592 | | $47,415 | | $19,435 |
Estimated Future Medicare Part D Subsidy | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2010 | | $1,395 | | $637 | | $811 | | $523 | | $529 | | $644 | | $94 |
| 2011 | | $1,534 | | $706 | | $834 | | $605 | | $555 | | $698 | | $108 |
| 2012 | | $1,699 | | $784 | | $986 | | $622 | | $584 | | $758 | | $139 |
| 2013 | | $1,874 | | $862 | | $1,078 | | $678 | | $612 | | $823 | | $170 |
| 2014 | | $2,050 | | $940 | | $1,168 | | $733 | | $629 | | $885 | | $207 |
| 2015 - 2019 | | $12,937 | | $5,960 | | $7,220 | | $4,466 | | $3,286 | | $5,143 | | $1,697 |
Estimated Future Medicare Part D Subsidy | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2013 | | $1,889 | | $835 | | $1,022 | | $584 | | $478 | | $722 | | $265 |
| 2014 | | $2,027 | | $910 | | $1,101 | | $639 | | $497 | | $770 | | $297 |
| 2015 | | $2,180 | | $992 | | $1,186 | | $691 | | $515 | | $821 | | $331 |
| 2016 | | $2,335 | | $1,079 | | $1,274 | | $747 | | $533 | | $874 | | $368 |
| 2017 | | $2,500 | | $1,172 | | $1,370 | | $805 | | $551 | | $928 | | $408 |
| 2018 - 2022 | | $15,201 | | $7,446 | | $8,492 | | $4,912 | | $2,991 | | $5,463 | | $2,797 |
Contributions
Entergy currently expects to contribute approximately $270$163.3 million to its qualified pension plans and approximately $76$82.5 million to other postretirement plans in 2010.2013. The expected 20102013 pension and other postretirement plan contributions of the Registrant Subsidiaries are shown below. The required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy's and each of the Registrant Subsidiaries’ pension contributions in the future.2013.
The Registrant Subsidiaries expect to contribute approximately the following to the pension and other postretirement plans in 2010:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Pension Contributions | | $73,128 | | $21,902 | | $27,050 | | $17,791 | | $5,078 | | $9,763 | | $12,487 |
| | | | | | | | | | | | | | | |
Other Postretirement Contributions | | $21,601 | | $8,373 | | $9,941 | | $5,002 | | $5,191 | | $7,745 | | $3,388 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries expect to contribute approximately the following to the qualified pension and other postretirement plans in 2013:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| | | | | | | | | | | | | | | |
| Pension Contributions | | $34,945 | | $11,198 | | $20,731 | | $7,969 | | $3,959 | | $6,666 | | $7,621 |
| Other Postretirement Contributions | | $26,675 | | $8,381 | | $10,173 | | $5,469 | | $3,669 | | $5,153 | | $4,090 |
Actuarial Assumptions
The assumed health care cost trend rate used in measuring the APBO of Entergy was 7.5% for 2010, gradually decreasing each successive year until it reaches 4.75% in 2016 and beyond. The assumed health care cost trend rate used in measuring the Net Other Postretirement Benefit Cost of Entergy was 8.5% for 2009, gradually decreasing each successive year until it reaches 4.75% in 2016 and beyond. A one percentage point change in the assumed health care cost trend rate for 2009 would have the following effects:
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
2009 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase /(Decrease) (In Thousands) |
| | | | | | | | | |
Entergy Corporation and its subsidiaries | | $138,924 | | $16,804 | | ($123,118) | | ($14,399) |
A one percentage point change in the assumed health care cost trend rate for 2009 would have the following effects for the Registrant Subsidiaries:
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2009 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase/(Decrease) (In Thousands) |
| | | | | | | | | |
| Entergy Arkansas | | $23,595 | | $2,804 | | ($21,148) | | ($2,421) |
| Entergy Gulf States Louisiana | | $15,948 | | $1,854 | | ($14,189) | | ($1,586) |
| Entergy Louisiana | | $14,915 | | $1,798 | | ($13,357) | | ($1,547) |
| Entergy Mississippi | | $7,094 | | $849 | | ($6,343) | | ($733) |
| Entergy New Orleans | | $4,908 | | $562 | | ($4,465) | | ($490) |
| Entergy Texas | | $10,765 | | $1,112 | | ($9,663) | | ($962) |
| System Energy | | $5,242 | | $692 | | ($4,609) | | ($587) |
The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2009,2012, and 20082011 were as follows:
| | | 2009 | | 2008 |
| | | | | |
| | Weighted-average discount rate: | | | |
| | Qualified pension | 6.10% - 6.30% | | 6.75% |
| | Other postretirement | 6.10% | | 6.70% |
| | Non-qualified pension | 5.40% | | 6.75% |
| | Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements| | 2012 | | 2011 |
| | | | |
| Weighted-average discount rate: | | | |
| Qualified pension | 4.31% - 4.50% | | 5.10% - 5.20% |
| Other postretirement | 4.36% | | 5.10% |
| Non-qualified pension | 3.37% | | 4.40% |
Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% |
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2009, 2008,2012, 2011, and 20072010 were as follows:
| | 2009 | | 2008 | | 2007 | 2012 | | 2011 | | 2010 |
| | | | | | | | | | | |
| Weighted-average discount rate: | | | | | | | | | | |
| Qualified pension | 6.75% | | 6.50% | | 6.00% | 5.10% - 5.20% | | 5.60% - 5.70% | | 6.10% - 6.30% |
| Other postretirement | 6.70% | | 6.50% | | 6.00% | 5.10% | | 5.50% | | 6.10% |
| Non-qualified pension | 6.75% | | 6.50% | | 6.00% | 4.40% | | 4.90% | | 5.40% |
Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% | | 3.25% | 4.23% | | 4.23% | | 4.23% |
Expected long-term rate of return on plan assets: | | | | | | | | | | |
| Taxable assets | 6.00% | | 5.50% | | 5.50% | |
| Non-taxable assets | 8.50% | | 8.50% | | 8.50% | |
| Pension assets | | 8.50% | | 8.50% | | 8.50% |
| Other postretirement non-taxable assets | | 8.50% | | 7.75% | | 7.75% |
| Other postretirement taxable assets | | 6.50% | | 5.50% | | 5.50% |
Entergy'sEntergy’s other postretirement benefit transition obligations are beingwere amortized over 20 years ending in 2012.
Accounting MechanismsThe assumed health care cost trend rate used in measuring Entergy’s December 31, 2012 APBO was 7.50% for pre-65 retirees and 7.25% for post-65 retirees for 2013, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees. The assumed health care cost trend rate used in measuring Entergy’s 2012 Net Other Postretirement Benefit Cost was 7.75% for pre-65 retirees and 7.50% for post-65 retirees for 2012, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for pre-65 retirees and 4.75% in 2022 and beyond for post-65 retirees. A one percentage point change in the assumed health care cost trend rate for 2012 would have the following effects:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
2012 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase /(Decrease) (In Thousands) |
| | | | | | | | | |
Entergy Corporation and its subsidiaries | | $274,059 | | $28,455 | | ($220,654) | | ($22,210) |
With regard to pension and other postretirement costs, Entergy calculatesA one percentage point change in the expected return on pension and other postretirement benefit plan assets by multiplyingassumed health care cost trend rate for 2012 would have the long-term expected rate of return on assets byfollowing effects for the market-related value (MRV) of plan assets. Entergy determines the MRV of pension plan assets by calculating a value that uses a 20-quarter phase-in of the difference between actual and expected returns. For other postretirement benefit plan assets Entergy uses fair value when determining MRV.Registrant Subsidiaries:
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2012 | | Impact on the APBO | | Impact on the sum of service costs and interest cost | | Impact on the APBO | | Impact on the sum of service costs and interest cost |
| | | Increase/(Decrease) (In Thousands) |
| | | | | | | | | |
| Entergy Arkansas | | $41,816 | | $3,994 | | ($33,880) | | ($3,138) |
| Entergy Gulf States Louisiana | | $31,702 | | $3,287 | | ($25,554) | | ($2,568) |
| Entergy Louisiana | | $30,780 | | $3,237 | | ($24,858) | | ($2,528) |
| Entergy Mississippi | | $13,728 | | $1,346 | | ($11,139) | | ($1,057) |
| Entergy New Orleans | | $8,410 | | $779 | | ($6,924) | | ($619) |
| Entergy Texas | | $19,647 | | $1,799 | | ($16,034) | | ($1,421) |
| System Energy | | $11,304 | | $1,279 | | ($9,027) | | ($994) |
Medicare Prescription Drug, Improvement and Modernization Act of 2003
In December 2003, the Medicare Prescription Drug, Improvement and Modernization Act of 2003 became law. The Act introduces a prescription drug benefit cost under Medicare (Part D), which started in 2006, as well as a federal subsidy to employers who provide a retiree prescription drug benefit that is at least actuarially equivalent to Medicare Part D.
The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2012 and 2011 Accumulated Postretirement Benefit Obligation by $316.6 million and $274 million, respectively, and reduced the 2012, 2011, and 2010 other postretirement benefit cost by $31.2 million, $33.0 million, and $26.6 million, respectively. In 2012, Entergy received $6 million in Medicare subsidies for prescription drug claims.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The actuarially estimated effect of future Medicare subsidies reduced the December 31, 2009 and 2008 Accumulated Postretirement Benefit Obligation by $215 million and $187 million, respectively, and reduced the 2009, 2008, and 2007 other postretirement benefit cost by $24.0 million, $24.7 million, and $26.5 million, respectively. In 2009, Entergy received $5.1 million in Medicare subsidies for prescription drug claims.
The actuarially estimated effect of future Medicare subsidies and the actual subsidies received for the Registrant Subsidiaries was as follows:
| | | Entergy Arkansas | | | Entergy Gulf States Louisiana | | | Entergy Louisiana | | | Entergy Mississippi | | | Entergy New Orleans | | | Entergy Texas | | | System Energy | |
| | | Increase/(Decrease) In Thousands | |
| Impact on 12/31/2009 APBO | | $ | (45,809 | ) | | $ | (22,227 | ) | | $ | (25,443 | ) | | $ | (14,824 | ) | | $ | (9,798 | ) | | $ | (16,652 | ) | | $ | (7,965 | ) |
| Impact on 12/31/2008 APBO | | $ | (40,610 | ) | | $ | (19,650 | ) | | $ | (22,222 | ) | | $ | (13,280 | ) | | $ | (9,135 | ) | | $ | (14,961 | ) | | $ | (6,628 | ) |
Impact on 2009 other postretirement benefit cost | | $ | (4,941 | ) | | $ | (3,257 | ) | | $ | (2,780 | ) | | $ | (1,562 | ) | | $ | (1,043 | ) | | $ | (958 | ) | | $ | (923 | ) |
Impact on 2008 other postretirement benefit cost | | $ | (5,063 | ) | | $ | (3,502 | ) | | $ | (2,824 | ) | | $ | (1,625 | ) | | $ | (1,114 | ) | | $ | (1,051 | ) | | $ | (945 | ) |
Impact on 2007 other postretirement benefit cost | | $ | (5,502 | ) | | $ | (4,888 | ) | | $ | (3,048 | ) | | $ | (1,753 | ) | | $ | (1,242 | ) | | $ | (688 | ) | | $ | (984 | ) |
Medicare subsidies received in 2009 | | $ | (1,194 | ) | | $ | (679 | ) | | $ | (762 | ) | | $ | (398 | ) | | $ | (421 | ) | | $ | (581 | ) | | $ | (120 | ) |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | Increase/(Decrease) In Thousands |
| Impact on 12/31/2012 APBO | | ($62,877) | | ($32,055) | | ($36,015) | | ($19,507) | | ($10,902) | | ($21,164) | | ($13,586) |
| Impact on 12/31/2011 APBO | | ($55,684) | | ($27,834) | | ($31,693) | | ($17,687) | | ($10,500) | | ($19,346) | | ($11,036) |
| | | | | | | | | | | | | | | |
Impact on 2012 other postretirement benefit cost | | ($5,791) | | ($3,660) | | ($3,643) | | ($1,799) | | ($995) | | ($1,321) | | ($1.400) |
Impact on 2011 other postretirement benefit cost | | ($6,309) | | ($3,923) | | ($3,889) | | ($2,016) | | ($1,170) | | ($1,528) | | ($1,403) |
Impact on 2010 other postretirement benefit cost | | ($5,254) | | ($3,401) | | ($3,143) | | ($1,649) | | ($1,070) | | ($1,109) | | ($1,068) |
| | | | | | | | | | | | | | | |
Medicare subsidies received in 2012 | | $1,331 | | $779 | | $908 | | $434 | | $396 | | $644 | | $170 |
Non-Qualified Pension Plans
Entergy also sponsors non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. Entergy recognized net periodic pension cost related to these plans of $23.6 million in 2009, $17.2 million in 2008, and $20.6 million in 2007. In 2009, Entergy recognized a $6.7 million settlement charge related to the payment of lump sum benefits out of the plan that is included in the non-qualified pension plan cost above. The projected benefit obligation was $147.9 million and $138.4 million as of December 31, 2009 and 2008, respectively. There were $0.2 million in plan assets for a pre-merger Entergy Gulf States Louisiana plan at December 31, 2008 and none at December 31, 2009. The accumulated benefit obligation was $134.1 million and $125.5 million as of December 31, 2009 and 2008, respectively.
Entergy's non-qualified, non-current pension liability at December 31, 2009 and 2008 was $124.1 million and $121.5 million, respectively; and its current liability was $23.8 million and $16.7 million, respectively. The unamortized transition asset, prior service cost and net loss are recognized in regulatory assets ($51.6 million at December 31, 2009 and $44.1 million at December 31, 2008) and accumulated other comprehensive income before taxes ($23 million at December 31, 2009 and $18.2 million at December 31, 2008.)
The Registrant Subsidiaries (except System Energy) participate in Entergy's non-qualified, non-contributory defined benefit pension plans that provide benefits to certain key employees. The net periodic pension cost for the non-qualified plans for 2009, 2008, and 2007 was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2009 | | $395 | | $1,245 | | $30 | | $174 | | $84 | | $743 |
| 2008 | | $533 | | $313 | | $28 | | $218 | | $48 | | $908 |
| 2007 | | $493 | | $1,268 | | $25 | | $175 | | $228 | | $922 |
Included in Entergy Gulf States Louisiana’s 2009 cost above is a $947 thousand settlement charge related to the payment of lump sum benefits out of the plan.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The projected benefit obligation for the non-qualified plans as of December 31, 2009 and 2008 was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2009 | | $3,443 | | $3,272 | | $198 | | $1,453 | | $608 | | $9,542 |
| 2008 | | $3,321 | | $6,470 | | $189 | | $1,232 | | $454 | | $11,701 |
The accumulated benefit obligation for the non-qualified plans as of December 31, 2009 and 2008 was as follows:
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| 2009 | | $3,180 | | $3,181 | | $189 | | $1,257 | | $478 | | $9,474 |
| 2008 | | $3,114 | | $6,131 | | $180 | | $1,048 | | $352 | | $11,634 |
The following amounts were recorded on the balance sheet as of December 31, 2009 and 2008:
2009 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| Current liabilities | | ($341) | | ($285) | | ($23) | | ($107) | | ($16) | | ($935) |
| Non-current liabilities | | ($3,102) | | ($2,986) | | ($175) | | ($1,346) | | ($592) | | ($8,607) |
| Total Funded Status | | ($3,443) | | ($3,272) | | ($198) | | ($1,453) | | ($608) | | ($9,542) |
| | | | | | | | | | | | | |
| Regulatory Asset | | $1,844 | | $685 | | $118 | | $592 | | $389 | | ($1,209) |
Accumulated other comprehensive income (before taxes) | | $- | | $160 | | $- | | $- | | $- | | $- |
2008 | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| Current liabilities | | ($332) | | ($583) | | ($23) | | ($105) | | ($16) | | ($1,269) |
| Non-current liabilities | | ($2,989) | | ($5,887) | | ($166) | | ($1,127) | | ($438) | | ($10,274) |
| Total Funded Status | | ($3,321) | | ($6,470) | | ($189) | | ($1,232) | | ($454) | | ($11,543) |
| | | | | | | | | | | | | |
| Regulatory Asset | | $1,736 | | $2,026 | | $114 | | $431 | | $314 | | $628 |
Accumulated other comprehensive income (before taxes) | | $- | | $358 | | $- | | $- | | $- | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Defined Contribution Plans
Entergy sponsors the Savings Plan of Entergy Corporation and Subsidiaries (System Savings Plan). The System Savings Plan is a defined contribution plan covering eligible employees of Entergy and its subsidiaries. The employing Entergy subsidiary makes matching contributions for all non-bargaining and certain bargaining employees to the System Savings Plan in an amount equal to 70% of the participants'participants’ basic contributions, up to 6% of their eligible earnings per pay period. The 70% match is allocated to investments as directed by the employee.
Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries II (established in 2001), the Savings Plan of Entergy Corporation and Subsidiaries IV (established in 2002), the Savings Plan of Entergy Corporation and Subsidiaries VI (established in April 2007), and the Savings Plan of Entergy Corporation and Subsidiaries VII (established in April 2007) to which matching contributions are also made. The plans are defined contribution plans that cover eligible employees, as defined by each plan, of Entergy and its subsidiaries. Effective June 3, 2010, employees participating in the Savings Plan of Entergy Corporation and Subsidiaries II (Savings Plan II) were transferred into the System Savings Plan when Savings Plan II merged into the System Savings Plan.
Entergy's subsidiaries'Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $41.9$43.7 million in 2009, $38.42012, $42.6 million in 2008,2011, and $36.6$41.8 million in 2007.2010. The majority of the contributions were to the System Savings Plan.
The Registrant Subsidiaries' 2009, 2008,Subsidiaries’ 2012, 2011, and 20072010 contributions to defined contribution plans were as follows:
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| 2009 | | $3,197 | | $1,828 | | $2,356 | | $1,906 | | $732 | | $1,712 |
| 2008 | | $3,144 | | $1,741 | | $2,172 | | $1,884 | | $697 | | $1,622 |
| 2007 | | $3,064 | | $1,635 | | $2,063 | | $1,796 | | $664 | | $1,637 |
Year | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| | | | | | | | | | | | | |
| 2012 | | $3,223 | | $1,842 | | $2,327 | | $1,875 | | $740 | | $1,601 |
| 2011 | | $3,183 | | $1,804 | | $2,260 | | $1,894 | | $725 | | $1,613 |
| 2010 | | $3,177 | | $1,792 | | $2,289 | | $1,886 | | $683 | | $1,626 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 12. STOCK-BASED COMPENSATION (Entergy Corporation)
Entergy grants stock options, and long-term incentiverestricted stock, performance units, and restricted liabilityunit awards to key employees of the Entergy subsidiaries under its Equity Ownership Plans which are shareholder-approved stock-based compensation plans. The Equity Ownership Plan, as restated in February 2003 (2003 Plan), had 706,950743,129 authorized shares remaining for long-term incentive and restricted liabilityunit awards as of December 31, 2009.2012. Effective January 1, 2007, Entergy'sEntergy’s shareholders approved the 2007 Equity Ownership and Long-Term Cash Incentive Plan (2007 Plan). The maximum aggregate number of common shares that can be issued from the 2007 Plan for stock-based awards is 7,000,000 with no more than 2,000,000 available for non-option grants. The 2007 Plan, which only applies to awards made on or after January 1, 2007, will expire after 10 years. As of December 31, 2009,2012, there were 2,569,9261,075,702 authorized shares remaining for stock-based awards, all of which are available for non-option grants. Effective May 6, 2011, Entergy’s shareholders approved the 2011 Equity Ownership and Long-Term Cash Incentive Plan (2011 Plan). The maximum number of common shares that can be issued from the 2011 Plan for stock-based awards is 5,500,000 with no more than 2,000,000 available for incentive stock option grants. The 2011 Plan, which only applies to awards made on or after May 6, 2011, will expire after 10 years. As of December 31, 2012, there were 4,263,138 authorized shares remaining for stock-based awards, including 2,000,0001,447,600 for non-optionincentive stock option grants.
Stock Options
Stock options are granted at exercise prices that equal the closing market price of Entergy Corporation common stock on the date of grant. Generally, stock options granted will become exercisable in equal amounts on each of the first three anniversaries of the date of grant. Unless they are forfeited previously under the terms of the grant, options expire ten years after the date of the grant if they are not exercised.
The following table includes financial information for stock options for each of the years presented:
| | 2009 | | 2008 | | 2007 |
| | (in Millions) |
| | | | | | |
| Compensation expense included in Entergy's Consolidated Net Income | $17.0 | | $17.0 | | $15.0 |
| Tax benefit recognized in Entergy's Consolidated Net Income | $6.0 | | $7.0 | | $6.0 |
| Compensation cost capitalized as part of fixed assets and inventory | $3.0 | | $3.0 | | $3.0 |
| | 2012 | | 2011 | | 2010 |
| | (In Millions) |
| | | | | | |
| Compensation expense included in Entergy’s Consolidated Net Income | $7.7 | | $10.4 | | $15.0 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $3.0 | | $4.0 | | $5.8 |
| Compensation cost capitalized as part of fixed assets and inventory | $1.5 | | $2.0 | | $2.9 |
Entergy determines the fair value of the stock option grants by considering factors such as lack of marketability, stock retention requirements, and regulatory restrictions on exercisability in accordance with accounting standards. The stock option weighted-average assumptions used in determining the fair values are as follows:
| | 2009 | | 2008 | | 2007 | 2012 | | 2011 | | 2010 |
| | | | | | | | | | | |
| Stock price volatility | 24.39% | | 18.9% | | 17.0% | 25.11% | | 24.25% | | 25.73% |
| Expected term in years | 5.33 | | 4.64 | | 4.59 | 6.55 | | 6.64 | | 5.46 |
| Risk-free interest rate | 2.22% | | 2.77% | | 4.85% | 1.22% | | 2.70% | | 2.57% |
| Dividend yield | 3.50% | | 2.96% | | 3.0% | 4.50% | | 4.20% | | 3.74% |
| Dividend payment per share | $3.00 | | $3.00 | | $2.16 | $3.32 | | $3.32 | | $3.24 |
Stock price volatility is calculated based upon the weeklydaily public stock price volatility of Entergy Corporation common stock over a period equal to the last four to five years.expected term of the award. The expected term of the options is based upon historical option exercises and the weighted average life of options when exercised and the estimated weighted average life of all vested but unexercised options. In 2008, Entergy implemented stock ownership guidelines for its senior executive officers. These guidelines require an executive officer
Entergy Corporation and Subsidiaries
Notes to Financial Statements
to own shares of Entergy Corporation common stock equal to a specified multiple of his or her salary. Until an executive officer achieves this ownership position the executive officer is required to retain 75% of the after-tax net profit upon exercise of the option to be held in Entergy Corporation common stock. The reduction in fair value of the stock options due to this restriction is based upon an estimate of the call option value of the reinvested gain discounted to present value over the applicable reinvestment period.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
A summary of stock option activity for the year ended December 31, 20092012 and changes during the year are presented below:
| | | Number of Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value | | Weighted- Average Contractual Life |
| | | | | | | | | |
| Options outstanding as of January 1, 2009 | | 11,098,331 | | $66.45 | | | | |
| | | | | | | | | |
| Options granted | | 1,084,800 | | $77.53 | | | | |
| Options exercised | | (802,319) | | $34.81 | | | | |
| Options forfeited/expired | | (59,741) | | $87.77 | | | | |
| | | | | | | | | |
| Options outstanding as of December 31, 2009 | | 11,321,071 | | $69.64 | | $138 million | | 5.3 years |
| | | | | | | | | |
| Options exercisable as of December 31, 2009 | | 8,786,486 | | $63.08 | | $165 million | | 4.5 years |
| | | | | | | | | |
Weighted-average grant-date fair value of options granted during 2009 | | $12.47 | | | | | | |
| | | Number of Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value | | Weighted- Average Contractual Life |
| | | | | | | | | |
| Options outstanding as of January 1, 2012 | | 10,459,418 | | $75.46 | | | | |
| | | | | | | | | |
| Options granted | | 552,400 | | $71.30 | | | | |
| Options exercised | | (1,407,159) | | $44.46 | | | | |
| Options forfeited/expired | | (46,313) | | $76.83 | | | | |
| Options outstanding as of December 31, 2012 | | 9,558,346 | | $79.77 | | $- | | 4.6 years |
| | | | | | | | | |
| Options exercisable as of December 31, 2012 | | 8,442,157 | | $80.61 | | $- | | 5.1 years |
Weighted-average grant-date fair value of options granted during 2012 | | $9.42 | | | | | | |
The weighted-average grant-date fair value of options granted during the year was $14.41$11.48 for 20082011 and $14.15$13.18 for 2007.2010. The total intrinsic value of stock options exercised was $35.6$39.8 million during 2009, $63.72012, $29.6 million during 2008,2011, and $116.7$36.6 million during 2007.2010. The intrinsic value, which has no effect on net income, of the stock options exercised is calculated by the difference in Entergy Corporation'sCorporation’s common stock price on the date of exercise and the exercise price of the stock options granted. Because Entergy’s year-end stock price is less than the weighted average exercise price, the aggregate intrinsic value of outstanding stock options as of December 31, 2012 was zero. The intrinsic value of “in the money” stock options is $7.8 million as of December 31, 2012. Entergy recognizes compensation cost over the vesting period of the options based on their grant-date fair value. The total fair value of options that vested was approximately $22$11 million during 2009, $182012, $16 million during 2008,2011, and $15$21 million during 2007.2010.
The following table summarizes information about stock options outstanding as of December 31, 2009:2012:
| | | Options Outstanding | | Options Exercisable | | Options Outstanding | | Options Exercisable |
Range of Exercise Prices | | As of 12/31/2009 | | Weighted-Avg. Remaining Contractual Life-Yrs. | | Weighted- Avg. Exercise Price | | Number Exercisable as of 12/31/2009 | | Weighted- Avg. Exercise Price | | As of 12/31/2012 | | Weighted-Avg. Remaining Contractual Life-Yrs. | | Weighted- Avg. Exercise Price | | Number Exercisable as of 12/31/2012 | | Weighted- Avg. Exercise Price |
| | | | | | | | | | | | | | | | | | | | | |
| $23 - $36.99 | | 60,782 | | 0.9 | | $23.00 | | 60,782 | | $23.00 | |
| $37 - $50.99 | | 3,215,531 | | 2.1 | | $41.28 | | 3,215,531 | | $41.28 | | 177,046 | | 0.1 | | $44.45 | | 177,046 | | $44.45 |
| $51 - $64.99 | | 1,080,613 | | 4.1 | | $58.43 | | 1,080,613 | | $58.43 | | 858,997 | | 1.2 | | $58.60 | | 858,997 | | $58.60 |
| $65 - $78.99 | | 3,674,831 | | 6.5 | | $71.69 | | 2,650,931 | | $69.43 | | 5,419,319 | | 5.3 | | $72.91 | | 4,303,130 | | $72.77 |
| $79 - $91.99 | | 1,720,448 | | 7.1 | | $91.81 | | 1,189,930 | | $91.81 | | 1,622,984 | | 4.1 | | $91.82 | | 1,622,984 | | $91.82 |
| $92 - $108.20 | | 1,568,866 | | 8.1 | | $108.20 | | 588,699 | | $108.20 | | 1,480,000 | | 5.1 | | $108.20 | | 1,480,000 | | $108.20 |
| $23 - $108.20 | | 11,321,071 | | 5.3 | | $69.64 | | 8,786,486 | | $63.08 | |
| | | | | | | | | | | | |
| $37 - $108.20 | | | 9,558,346 | | 4.6 | | $79.77 | | 8,442,157 | | $80.61 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
20092012 not yet recognized is approximately $17$5.2 million and is expected to be recognized onover a weighted-average period of 1.6 years.
Entergy Corporation and Subsidiaries
Notes to Financial StatementsRestricted Stock Awards
In January 2012 the Board approved and Entergy granted 339,700 restricted stock awards under the 2011 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January 26, 2012 and were valued at $71.30 per share, which was the closing price of Entergy Corporation’s common stock on that date. One-third of the restricted stock awards will vest upon each anniversary of the grant date and are expensed ratably over the three year vesting period. Shares of restricted stock have the same dividend and voting rights as other common stock and are considered issued and outstanding shares of Entergy upon vesting.
The following table includes financial information for restricted stock for each of the years presented:
| | 2012 | | 2011 | | 2010 |
| | (In Millions) |
| | | | | | |
| Compensation expense included in Entergy’s Consolidated Net Income | $11.4 | | $3.9 | | $- |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $4.4 | | $1.5 | | $- |
| Compensation cost capitalized as part of fixed assets and inventory | $2.0 | | $0.7 | | $- |
Long-Term Incentive AwardsPerformance Unit Program
Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which are equal to the cash value of shares of Entergy Corporation common stock at the end of the performance period, which is the last trading day of the year. Performance units will pay out to the extent that the performance conditions are satisfied. In addition to the potential for equivalent share appreciation or depreciation, performance units will earn the cash equivalent of the dividends paid during the three-year performance period applicable to each plan. The costs of incentive awards are charged to income over the three-year period. Beginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program will be settled in shares of Entergy common stock rather than cash. In January 2012 the Board approved and Entergy granted 176,742 performance units under the 2011 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January 27, 2012, and were valued at $67.11 per share. Entergy considers factors, primarily market conditions, in determining the value of the performance units. Shares of the performance units have the same dividend and voting rights as other common stock, are considered issued and outstanding shares of Entergy upon vesting, and are expensed ratably over the three-year vesting period.
The following table includes financial information for the long-term incentive awardsperformance units for each of the years presented:
| | 2009 | | 2008 | | 2007 |
| | (In Millions) |
| | | | | | |
| Fair value of long-term incentive awards as of December 31, | $17 | | $41 | | $54 |
Compensation expense included in Entergy's Consolidated Net Income for the year | $6 | | $20 | | $35 |
| Tax benefit recognized in Entergy's Consolidated Net Income for the year | $2 | | $8 | | $14 |
| Compensation cost capitalized as part of fixed assets and inventory | $1 | | $5 | | $6 |
| | 2012 | | 2011 | | 2010 |
| | (In Millions) |
| | | | | | |
| Fair value of long-term performance units as of December 31, | $4.3 | | $7.3 | | $10.1 |
| Compensation expense included in Entergy’s Consolidated Net Income | ($5.0) | | $0.7 | | ($0.9) |
| Tax benefit (expense) recognized in Entergy’s Consolidated Net Income | ($1.9) | | $0.3 | | ($0.4) |
| Compensation cost capitalized as part of fixed assets and inventory | ($0.9) | | $0.1 | | $0.1 |
Entergy paid $30.6 millionThere was no payout in 20092012 for awards earned under the Long-Term Incentive Plan. The distribution isperformance units granted in 2009 applicable to the 2006 - 20082009 – 2011 performance period.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Restricted Unit Awards
Entergy grants restricted unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted units are equal to the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted unit awards granted is 4036 months. As of December 31, 2009,2012, there were 234,50278,820 unvested restricted units that are expected to vest over an average period of 2217 months.
The following table includes financial information for restricted unit awards for each of the years presented:
| | 2009 | | 2008 | | 2007 | 2012 | | 2011 | | 2010 |
| | (In Millions) | (In Millions) |
| | | | | | | | | | | |
| Fair value of restricted awards as of December 31, | $4.6 | | $7.5 | | $11.2 | $3.0 | | $6.6 | | $8.3 |
Compensation expense included in Entergy's Consolidated Net Income for the year | $2.0 | | $2.0 | | $6.5 | |
| Tax benefit recognized in Entergy's Consolidated Net Income for the year | $0.8 | | $0.8 | | $2.5 | |
| Compensation expense included in Entergy’s Consolidated Net Income | | $1.3 | | $3.7 | | $3.9 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | | $0.5 | | $1.4 | | $1.5 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.5 | | $0.4 | | $1.1 | $0.2 | | $0.7 | | $0.9 |
Entergy paid $5.1$5.3 million in 20092012 for awards under the Restricted Units Awards Plan.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy'sEntergy’s reportable segments as of December 31, 20092012 are Utility and Non-Utility Nuclear.Entergy Wholesale Commodities. Utility generates, transmits, distributes,includes the generation, transmission, distribution, and sellssale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and provides natural gas utility service in portions of Louisiana. Non-Utility Nuclear ownsEntergy Wholesale Commodities includes the ownership and operatesoperation of six nuclear power plants located in the northern United States and is primarily focused on sellingthe sale of the electric power produced by those plants to wholesale customers. "All Other"Entergy Wholesale Commodities also includes the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. “All Other” includes the parent company, Entergy Corporation, and other business activity, including the non-nuclear wholesale assets business and earnings on the proceeds of sales of previously-owned businesses. As a result of the Entergy New Orleans bankruptcy filing, Entergy discontinued the consolidation of Entergy New Orleans retroactive to January 1, 2005, and reported Entergy New Orleans results under the equity method of accounting in the Utility segment in 2006. On May 7, 2007, the bankruptcy judge entered an order confirming Entergy New Orleans' plan of reorganization. With confirmation of the plan of reorganization, Entergy reconsolidated Entergy New Orleans in the second quarter 2007, retroactive to January 1, 2007.
Entergy'sIn the fourth quarter 2012, Entergy moved two subsidiaries from All Other to the Entergy Wholesale Commodities segment financialto improve the alignment of certain intercompany items and income tax activity. The 2011 and 2010 information is as follows:in the tables below has been restated to reflect the change.
2009 | Utility | | Non-Utility Nuclear* | | All Other* | | Eliminations | | Consolidated |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | $8,055,353 | | $2,555,254 | | $161,506 | | ($26,463) | | $10,745,650 |
| Deprec., amort. & decomm. | $1,025,922 | | $240,747 | | $15,169 | | $- | | $1,281,838 |
| Interest and dividend income | $180,505 | | $170,033 | | $88,106 | | ($202,016) | | $236,628 |
Equity in loss of unconsolidated equity affiliates | $1 | | $- | | ($7,794) | | $- | | ($7,793) |
| Interest and other charges | $462,206 | | $55,884 | | $180,931 | | ($128,577) | | $570,444 |
| Income taxes (benefits) | $388,682 | | $379,266 | | ($135,208) | | $- | | $632,740 |
| Consolidated net income (loss) | $708,905 | | $631,020 | | ($15,437) | | ($73,438) | | $1,251,050 |
| Total assets | $29,694,732 | | $10,590,809 | | ($294,277) | | ($2,626,667) | | $37,364,597 |
| Investment in affiliates - at equity | $200 | | $- | | $39,380 | | $- | | $39,580 |
Cash paid for long-lived asset additions | $1,872,997 | | $654,003 | | $1,719 | | $- | | $2,528,719 |
2008 | Utility | | Non-Utility Nuclear* | | All Other* | | Eliminations | | Consolidated |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | $10,318,630 | | $2,558,378 | | $241,715 | | ($24,967) | | $13,093,756 |
| Deprec., amort. & decomm. | $984,651 | | $220,128 | | $15,490 | | $- | | $1,220,269 |
| Interest and dividend income | $122,657 | | $112,129 | | $116,830 | | ($153,744) | | $197,872 |
Equity in loss of unconsolidated equity affiliates | ($3) | | $- | | ($11,681) | | $- | | ($11,684) |
| Interest and other charges | $425,216 | | $53,926 | | $243,745 | | ($113,966) | | $608,921 |
| Income taxes (benefits) | $371,281 | | $319,107 | | ($87,390) | | $- | | $602,998 |
| Consolidated net income (loss) | $605,144 | | $797,280 | | ($122,110) | | ($39,779) | | $1,240,535 |
| Total assets | $28,810,147 | | $7,848,195 | | $2,586,456 | | ($2,627,980) | | $36,616,818 |
| Investment in affiliates - at equity | $199 | | $- | | $66,048 | | $- | | $66,247 |
Cash paid for long-lived asset additions | $2,478,014 | | $478,285 | | $18,730 | | $- | | $2,975,029 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2007 | Utility | | Non-Utility Nuclear* | | All Other* | | Eliminations | | Consolidated |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues | $9,255,075 | | $2,029,666 | | $225,216 | | ($25,559) | | $11,484,398 |
| Deprec., amort. & decomm. | $939,152 | | $177,872 | | $14,586 | | $- | | $1,131,610 |
| Interest and dividend income | $124,992 | | $107,754 | | $88,066 | | ($81,901) | | $238,911 |
Equity in earnings of unconsolidated equity affiliates | ($2) | | $- | | $3,178 | | $- | | $3,176 |
| Interest and other charges | $422,382 | | $34,738 | | $261,832 | | ($81,900) | | $637,052 |
| Income taxes (benefits) | $382,025 | | $230,407 | | ($98,015) | | $- | | $514,417 |
| Consolidated net income (loss) | $704,393 | | $539,200 | | ($83,639) | | $- | | $1,159,954 |
| Total assets | $26,174,159 | | $7,014,484 | | $1,982,429 | | ($1,528,070) | | $33,643,002 |
| Investment in affiliates - at equity | $202 | | $- | | $78,790 | | $- | | $78,992 |
Cash paid for long-lived asset additions | $1,497,174 | | $821,790 | | $2,754 | | $1,255 | | $2,322,973 |
2012 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | | $8,005,091 | | $2,326,309 | | $4,048 | | ($33,369) | | $10,302,079 |
| Deprec., amort. & decomm. | | $1,076,845 | | $248,143 | | $4,357 | | $- | | $1,329,345 |
| Interest and investment income | | $150,292 | | $105,062 | | $30,656 | | ($158,234) | | $127,776 |
| Interest expense | | $476,485 | | $17,900 | | $126,913 | | ($52,014) | | $569,284 |
| Income taxes | | $49,340 | | $61,329 | | ($79,814) | | $- | | $30,855 |
| Consolidated net income (loss) | | $960,322 | | $40,427 | | ($26,167) | | ($106,219) | | $868,363 |
| Total assets | | $35,438,130 | | $9,623,345 | | ($509,985) | | ($1,348,988) | | $43,202,502 |
| Investment in affiliates - at equity | | $199 | | $46,539 | | $- | | $- | | $46,738 |
Cash paid for long-lived asset additions | | $3,182,695 | | $577,652 | | $619 | | $- | | $3,760,966 |
2011 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | | $8,841,828 | | $2,413,773 | | $4,157 | | ($30,685) | | $11,229,073 |
| Deprec., amort. & decomm. | | $1,027,597 | | $260,643 | | $4,557 | | $- | | $1,292,797 |
| Interest and investment income | | $158,737 | | $99,762 | | $16,368 | | ($145,873) | | $128,994 |
| Interest expense | | $455,739 | | $33,067 | | $60,113 | | ($35,292) | | $513,627 |
| Income taxes | | $27,311 | | $176,286 | | $82,666 | | $- | | $286,263 |
| Consolidated net income (loss) | | $1,123,866 | | $491,846 | | ($137,760) | | ($110,580) | | $1,367,372 |
| Total assets | | $32,734,549 | | $9,796,529 | | $228,691 | | ($2,058,070) | | $40,701,699 |
| Investment in affiliates - at equity | | $199 | | $44,677 | | $- | | $- | | $44,876 |
Cash paid for long-lived asset additions | | $2,351,913 | | $1,048,146 | | ($402) | | $- | | $3,399,657 |
2010 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| | | | | | | | | | | |
| Operating revenues | | $8,941,332 | | $2,566,156 | | $7,442 | | ($27,353) | | $11,487,577 |
| Deprec., amort. & decomm. | | $1,006,385 | | $270,663 | | $4,582 | | $- | | $1,281,630 |
| Interest and investment income | | $182,493 | | $140,729 | | $73,808 | | ($212,953) | | $184,077 |
| Interest expense | | $493,241 | | $102,728 | | $98,594 | | ($119,396) | | $575,167 |
| Income taxes | | $454,227 | | $247,775 | | ($84,763) | | $- | | $617,239 |
| Consolidated net income | | $829,719 | | $450,104 | | $84,039 | | ($93,557) | | $1,270,305 |
| Total assets | | $31,080,240 | | $10,102,817 | | ($714,968) | | ($1,782,813) | | $38,685,276 |
| Investment in affiliates - at equity | | $199 | | $40,498 | | $- | | $- | | $40,697 |
Cash paid for long-lived asset additions | | $1,766,609 | | $687,313 | | $75 | | $- | | $2,453,997 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Businesses marked with * are sometimes referred to as the "competitive businesses," with the exception of the parent company, Entergy Corporation.“competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy'sEntergy’s goodwill is related to the Utility segment.
Earnings were negatively affectedOn April 5, 2010, Entergy announced that, effective immediately, it planned to unwind the business infrastructure associated with its proposed plan to spin-off its non-utility nuclear business. As a result of the plan to unwind the business infrastructure, Entergy recorded expenses in the fourth quarter 2007 by expensesEntergy Wholesale Commodities segment. Other operating and maintenance expense in 2010 includes the write-off of $22.2$64 million ($13.6of capital costs, primarily for software that will not be utilized. Interest charges in 2010 include the write-off of $39 million net-of-tax)of debt financing costs, primarily incurred for Utility and $29.9the $1.2 billion credit facility related to the planned spin-off of Entergy’s non-utility nuclear business that will not be used. Approximately $16 million ($18.4 million net-of-tax) for Non-Utility Nuclear recordedof other costs were incurred in 2010 in connection with aunwinding the planned non-utility nuclear operations fleet alignment. This process was undertaken with the goals of eliminating redundancies, capturing economies of scale, and clearly establishing organizational governance. Most of the expenses related to the voluntary severance program offered to employees. Approximately 200 employees from the Non-Utility Nuclear business and 150 employees in the Utility business accepted the voluntary severance program offers.spin-off transaction.
Geographic Areas
For the years ended December 31, 20092012, 2011, and 2008,2010, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 20092012 and 2008,2011, Entergy had no long-lived assets located outside of the United States.
Registrant Subsidiaries
Each of the Registrant Subsidiaries has one reportable segment, which is an integrated utility business, except for System Energy, which is an electricity generation business. Each of the Registrant Subsidiaries'Subsidiaries’ operations is managed on an integrated basis by that company because of the substantial effect of cost-based rates and regulatory oversight on the business process, cost structures, and operating results.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 14. EQUITY METHOD INVESTMENTS (Entergy Corporation)
As of December 31, 2009,2012, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:
| Investment | | Ownership | | Description |
| | | | |
Entergy-Koch | | 50% partnership interest | | Entergy-Koch was in the energy commodity marketing and trading business and gas transportation and storage business until the fourth quarter 2004 when these businesses were sold. In December 2009, Entergy reorganized its investment in Entergy-Koch, received a $25.6 million cash distribution, and received a distribution of certain software owned by the joint venture. |
| | | | | |
| RS Cogen LLC | | 50% member interest | | Co-generation project that produces power and steam on an industrial and merchant basis in the Lake Charles, Louisiana area. |
| | | | | |
| Top Deer | | 50% member interest | | Wind-powered electric generation joint venture. |
Following is a reconciliation of Entergy'sEntergy’s investments in equity affiliates:
| | | 2009 | | 2008 | | 2007 |
| | | (In Thousands) |
| | | | | | | |
| Beginning of year | | $66,247 | | $78,992 | | $229,089 |
| Entergy New Orleans (a) | | - | | - | | (153,988) |
| Income (loss) from the investments | | (7,793) | | (11,684) | | 3,176 |
| Dispositions and other adjustments | | (18,874) | | (1,061) | | 715 |
| End of year | | $39,580 | | $66,247 | | $78,992 |
(a) | As a result of Entergy New Orleans' bankruptcy filing in September 2005, Entergy deconsolidated Entergy New Orleans and reflected Entergy New Orleans' financial results under the equity method of accounting retroactive to January 1, 2005. In May 2007, with confirmation of the plan of reorganization, Entergy reconsolidated Entergy New Orleans retroactive to January 1, 2007 and no longer accounts for Entergy New Orleans under the equity method of accounting. See Note 18 to the financial statements for further discussion of the bankruptcy proceeding. |
Related-party transactions and guarantees
See Note 18 to the financial statements for a discussion of the Entergy New Orleans bankruptcy proceedings and activity between Entergy and Entergy New Orleans.
Entergy Gulf States Louisiana purchased approximately $49.3 million, $82.5 million, and $68.4 million of electricity generated from Entergy's share of RS Cogen in 2009, 2008, and 2007, respectively. Entergy's operating transactions with its other equity method investees were not significant in 2009, 2008, or 2007.| | | 2012 | | 2011 | | 2010 |
| | | (In Thousands) |
| | | | | | | |
| Beginning of year | | $44,876 | | $40,697 | | $39,580 |
| Income (loss) from the investments | | 1,162 | | (88) | | (2,469) |
| Dispositions and other adjustments | | 700 | | 4,267 | | 3,586 |
| End of year | | $46,738 | | $44,876 | | $40,697 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Transactions with equity method investees
Entergy Gulf States Louisiana purchased approximately $2.8 million, $41.1 million, and $50.8 million of electricity generated from Entergy’s share of RS Cogen in 2012, 2011, and 2010, respectively. Entergy’s operating transactions with its other equity method investees were not significant in 2012, 2011, or 2010.
NOTE 15. ACQUISITIONS AND DISPOSITIONS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Mississippi)
CalcasieuAcquisitions
Hot Spring Energy Facility
In March 2008,November 2012, Entergy Gulf StatesArkansas purchased the Hot Spring Energy Facility, a 620 MW combined-cycle natural gas turbine unit located in Malvern, Arkansas, from KGen Hot Spring LLC for approximately $253 million. The FERC and the APSC approved the transaction.
Hinds Energy Facility
In November 2012, Entergy Mississippi purchased the Hinds Energy Facility, a 450 MW combined-cycle natural gas turbine unit located in Jackson, Mississippi, from KGen Hinds LLC for approximately $206 million. The FERC and the MPSC approved the transaction.
Acadia
In April 2011, Entergy Louisiana purchased Unit 2 of the Calcasieu Generating Facility,Acadia Energy Center, a 322580 MW simple-cycle gas-fired power plantgenerating unit located near Eunice, Louisiana, from an independent power producer. The Acadia Energy Center, which entered commercial service in 2002, consists of two combined-cycle gas-fired generating units, each nominally rated at 580 MW. Entergy Louisiana purchased 100 percent of Acadia Unit 2 and a 50 percent ownership interest in the city of Sulphur in southwestern Louisiana,facility’s common assets for approximately $56 million from$300 million. In a subsidiary of Dynegy, Inc. Entergy Gulf States Louisiana receivedseparate transaction, Cleco Power acquired Acadia Unit 1 and the plant, materials and supplies, SO2 emission allowances, and related real estateother 50 percent interest in the transaction.facility’s common assets. Cleco Power will serve as operator for the entire facility. The FERC and the LPSC approved the acquisition.transaction.
OuachitaRhode Island State Energy Center
In September 2008,December 2011 a subsidiary in the Entergy ArkansasWholesale Commodities business segment purchased the Ouachita Plant,Rhode Island State Energy Center, a 789583 MW three-trainnatural gas-fired combined cyclecombined-cycle generating turbine (CCGT) electric power plant located 20 miles south of the Arkansas state line near Sterlington, Louisiana, for approximately $210 millionin Johnston, Rhode Island, from a subsidiary of CogentrixNextEra Energy Inc. Entergy Arkansas received the plant, materials and supplies, and related real estateResources, for approximately $346 million. The Rhode Island State Energy Center began commercial operation in the transaction. The FERC and the APSC approved the acquisition. The APSC also approved the recovery of the acquisition and ownership costs through a rate rider and the planned sale of one-third of the capacity and energy to Entergy Gulf States Louisiana.
The LPSC also approved the purchase of one-third of the capacity and energy by Entergy Gulf States Louisiana, subject to certain conditions, including a study to determine the costs and benefits of Entergy Gulf States Louisiana exercising an option to purchase one-third of the plant (Unit 3) from Entergy Arkansas. In April 2009, Entergy Gulf States Louisiana made a filing with the LPSC seeking approval of Entergy Gulf States Louisiana exercising its option to convert its purchased power agreement into the ownership interest in Unit 3 and a one-third interest in the Ouachita common facilities. In September 2009 the LPSC, pursuant to an uncontested settlement, approved the acquisition and a cost recovery mechanism. Entergy Gulf States Louisiana purchased Unit 3 and a one-third interest in the Ouachita common facilities for $75 million in November 2009.2002.
Palisades Purchased Power Agreement
In AprilEntergy’s purchase of the Palisades plant in 2007 Entergy's Non-Utility Nuclear business purchased the 798 MW Palisades nuclear energy plant located near South Haven, Michigan from Consumers Energy Company for a net cash payment of $336 million. Entergy received the plant, nuclear fuel, inventories, and other assets. The liability to decommission the plant, as well as related decommissioning trust funds, was also transferred to Entergy's Non-Utility Nuclear business. Entergy's Non-Utility Nuclear business executedincluded a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant'splant’s output, excluding any future uprates. Prices under the PPA range from $43.50/MWh in 2007 to $61.50/MWh in 2022, and the average price under the PPA is $51/MWh. In the first quarter 2007, the NRC renewed Palisades' operating license until 2031. As part of the transaction, Entergy's Non-Utility Nuclear business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Palisades' financial results since April 2007 are included in Entergy's Non-Utility Nuclear business segment. The following table summarizes the assets acquired and liabilities assumed at the date of acquisition.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | Amount |
| | (In Millions) |
| | |
Plant (including nuclear fuel) | | $727
|
Decommissioning trust funds | | 252 |
Other assets | | 41 |
Total assets acquired | | 1,020 |
| | |
Purchased power agreement (below market) | | 420 |
Decommissioning liability | | 220 |
Other liabilities | | 44 |
Total liabilities assumed | | 684 |
| | |
Net assets acquired | | $336 |
Subsequent to the closing, Entergy received approximately $6 million from Consumers Energy Company as part of the Post-Closing Adjustment defined in the Asset Sale Agreement. The Post-Closing Adjustment amount resulted in an approximately $6 million reduction in plant and a corresponding reduction in other liabilities.
For the PPA, which was at below-market prices at the time of the acquisition, Non-Utility NuclearEntergy will amortize a liability to revenue over the life of the agreement. The amount that will be amortized each period is based upon the difference between the present value calculated at the date of acquisition of each year'syear’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $53$17 million in 2009, $762012, $43 million in 2008,2011, and $50$46 million in 2007.2010. The amounts to be amortized to revenue for the next five years will be $46 million for 2010, $43 million for 2011, $17$18 million in 2012, $18 million for 2013, and $16 million for 2014.2014, $15 million for 2015, $13 million for 2016, and $12 million for 2017.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NYPA Value Sharing Agreements
Non-Utility Nuclear'sEntergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Non-Utility NuclearEntergy subsidiaries and NYPA amended and restated the value sharing agreements to clarify and amend certain provisions of the original terms. Under the amended value sharing agreements, Non-Utility NuclearEntergy subsidiaries will make annual payments to NYPA based on the generation output of the Indian Point 3 and FitzPatrick plants from January 2007 through December 2014. Non-Utility NuclearEntergy subsidiaries will pay NYPA $6.59 per MWh for power sold from Indian Point 3, up to an annual cap of $48 million, and $3.91 per MWh for power sold from FitzPatrick, up to an annual cap of $24 million. The annual payment for each year'syear’s output is due by January 15 of the following year. Non-Utility NuclearEntergy will record itsthe liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. An amount equal to the liability will be recorded to the plant asset account as contingent purchase price consideration for the plants. In 2009, 2008,2012, 2011, and 2007, Non-Utility Nuclear2010, Entergy Wholesale Commodities recorded approximately $72 million as plant for generation during each of those years. This amount will be depreciated over the expected remaining useful life of the plants.
In August 2008, Non-Utility Nuclear entered into a resolution of a dispute with NYPA over the applicability of the value sharing agreements to its FitzPatrick and Indian Point 3 nuclear power plants after the planned spin-off of the Non-Utility Nuclear business. Under the resolution, Non-Utility Nuclear agreed not to treat the separation as a "Cessation Event" that would terminate its obligation to make the payments under the value sharing agreements. As a result, after the spin-off transaction, Enexus will continue to be obligated to make payments to NYPA under the amended and restated value sharing agreements.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Asset Dispositions
Entergy-Koch BusinessesHarrison County
In the fourth quarter 2004, Entergy-Koch2010, an Entergy Wholesale Commodities subsidiary sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales. Due to the November 2006 expiration of contingencies on the sale of Entergy-Koch's trading business, and the corresponding release to Entergy-Koch of sales proceeds held in escrow, Entergy recorded a gain related to its Entergy-Koch investment of approximately $55 million, net-of-tax,ownership interest in the fourth quarter 2006 and received additional cash distributionsHarrison County Power Project 550 MW combined-cycle plant to two Texas electric cooperatives that owned a minority share of approximately $163 million. In December 2009, Entergy reorganized its investment in Entergy-Koch, received a $25.6 million cash distribution, and received a distribution of certain software owned by the joint venture.
Other
In the second quarter 2008,Marshall, Texas unit. Entergy sold its remaining interest in Warren Power61 percent share of the plant for $219 million and realized a gain of $11.2$44.2 million ($6.927.2 million net-of-tax) on the sale.
NOTE 16. RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Market and Commodity Risks
In the normal course of business, Entergy is exposed to a number of market and commodity risks. Market risk is the potential loss that Entergy may incur as a result of changes in the market or fair value of a particular instrument or commodity. All financial and commodity-related instruments, including derivatives, are subject to market risk. Entergy is subject to a number of commodity and market risks, including:
| Type of Risk | | Affected Businesses |
| | | |
| Power price risk | | Utility, Non-Utility Nuclear, Non-nuclear wholesale assetsEntergy Wholesale Commodities |
| Fuel price risk | | Utility, Non-Utility Nuclear, Non-nuclear wholesale assets |
Foreign currency exchange rate risk | | Utility, Non-Utility Nuclear, Non-nuclear wholesale assetsEntergy Wholesale Commodities |
| Equity price and interest rate risk - investments | | Utility, Non-Utility NuclearEntergy Wholesale Commodities |
Entergy manages a portion of these risks using derivative instruments, some of which are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal salessale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, and fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include natural gas and electricity futures, forwards, swaps and options; foreign currency forwards;options, and interest rate swaps. Entergy will occasionally enter into financially settled swap and option contracts to manage market risk under certain hedging transactions which may or may not be designated as hedging instruments. Entergy enters into derivatives only to manage natural risks inherent in its physical or financial assets or liabilities.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy manages fuel price riskvolatility for its Louisiana jurisdictions (Entergy Gulf States Louisiana Entergy Louisiana, and Entergy New Orleans)Louisiana) and Entergy Mississippi primarily through the purchase of short-term natural gas swaps. These swaps are marked-to-market with offsetting regulatory assets or liabilities. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation and projected winter purchases for gas distribution at Entergy Gulf States Louisiana and Entergy New Orleans.
Entergy Corporation and Subsidiaries
Notes to Financial StatementsLouisiana.
Entergy'sEntergy’s exposure to market risk is determined by a number of factors, including the size, term, composition, and diversification of positions held, as well as market volatility and liquidity. For instruments such as options, the time period during which the option may be exercised and the relationship between the current market price of the underlying instrument and the option'soption’s contractual strike or exercise price also affects the level of market risk. A significant factor influencing the overall level of market risk to which Entergy is exposed is its use of hedging techniques to mitigate such risk. Entergy manages market risk by actively monitoring compliance with stated risk management policies as well as monitoring the effectiveness of its hedging policies and strategies. Entergy'sEntergy’s risk management policies limit the amount of total net exposure and rolling net exposure during the stated periods. These policies, including related risk limits, are regularly assessed to ensure their appropriateness given Entergy'sEntergy’s objectives.
Derivatives
The fair values of Entergy'sEntergy’s derivative instruments in the consolidated balance sheet as of December 31, 20092012 are as follows:
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (a) | | Business |
| | | | | | | | | |
Derivatives designated as hedging instruments | | | | | | | | |
| | | | | | | | |
| Assets: | | | | | | | | |
Electricity futures, forwards,swaps and swapsoptions | | Prepayments and other (current portion) | | $109123 million | | Non-Utility Nuclear
($-) | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $46 million | | ($10) million | | Entergy Wholesale Commodities |
| | | | | | | | |
| Liabilities: | | | | | | | | |
Electricity futures, forwards,swaps and swapsoptions | | Other deferred debits and other assetsnon-current liabilities (non-current portion) | | $9118 million | | ($11) million | | Entergy Wholesale Commodities |
Non-Utility Nuclear
| Derivatives not designated as hedging instruments |
| | | | | | | |
Derivatives not designated as hedging instruments
| | | | | | | | |
| Assets: | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $22 million | | ($-) | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $24 million | | ($14) million | | Entergy Wholesale Commodities |
| | | | | | | | |
| Liabilities: | | | | | | | | |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $19 million | | ($13) million | | Entergy Wholesale Commodities |
| Natural gas swaps | | Prepayments and otherOther current liabilities | | $8 million | | ($-) | | Utility |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2011 are as follows:
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (a) | | Business |
| | | | | | | | |
| Derivatives designated as hedging instruments | | | | | | | | |
| | | | | | | | |
| Assets: | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $197 million | | ($25) million | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $112 million | | ($1) million | | Entergy Wholesale Commodities |
| | | | | | | | |
| Liabilities: | | | | | | | | |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $1 million | | ($1) million | | Entergy Wholesale Commodities |
| Derivatives not designated as hedging instruments | | | | | | | | |
| | | | | | | | |
| Assets: | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $37 million | | ($8) million | | Entergy Wholesale Commodities |
| | | | | | | | |
| Liabilities: | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $33 million | | ($33) million | | Entergy Wholesale Commodities |
| Natural gas swaps | | Other current liabilities | | $30 million | | ($-) | | Utility |
| (a) | The balances of derivative assets and liabilities in these tables are presented gross. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented on the Entergy Consolidated Balance Sheets on a net basis in accordance with accounting guidance for Derivatives and Hedging. |
The effect of Entergy'sEntergy’s derivative instruments designated as cash flow hedges on the consolidated income statements of income for the yearyears ended December 31, 2009 is2012, 2011, and 2010 are as follows:
Instrument | | Amount of gain (loss) recognized in OCI (effective portion)other comprehensive income | | Income Statement of Income location | | Amount of gain (loss) reclassified from accumulated OCI AOCI into income (effective portion) |
| | | | | | | |
Electricity futures, forwards,
and swaps
2012 | | | | | | |
| Electricity swaps and options | | $315111 million | | Competitive businesses operating revenues | | $322268 million |
| | | | | | | |
| 2011 | | | | | | |
| Electricity swaps and options | | $296 million | | Competitive businesses operating revenues | | $168 million |
| | | | | | |
| 2010 | | | | | | |
| Electricity swaps and options | | $206 million | | Competitive businesses operating revenues | | $220 million |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Electricity over-the-counter swapsinstruments that financially settle against day-ahead power pool prices are used to manage price exposure for Non-Utility NuclearEntergy Wholesale Commodities generation. Based on market prices as of December 31, 2009,2012, cash flow hedges relating to power sales totaled $200$151 million of net gains, of which approximately $109unrealized gains. Approximately $123 million areis expected to be reclassified from accumulated other comprehensive income (OCI)(AOCI) to operating revenues in the next twelve months. The actual amount reclassified from accumulated OCI,AOCI, however, could vary due to future changes in market prices. Gains totaling approximately $322$268 million, $168 million, and $220 million were realized on the maturity of cash flow hedges, before taxes of $94 million, $59 million, and $77 million, for 2009.the years ended December 31, 2012, 2011, and 2010, respectively. Unrealized gains or losses recorded in OCIother comprehensive income result from hedging power output at the Non-Utility NuclearEntergy Wholesale Commodities power plants. The related gains or losses from hedging power are included in operating revenues when realized. The maximum length of time over which Entergy is currently hedging the variability in future cash flows with derivatives for forecasted power transactions as ofat December 31, 20092012 is approximately threetwo years. Planned generation sold forwardcurrently under contract from Non-Utility NuclearEntergy Wholesale Commodities nuclear power plants as of December 31, 2009 is 88%85% for 20102013, of which approximately 40%51% is sold under financial hedgesderivatives and the remainder under normal purchase/normal sale contracts. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($14) million, ($6) million, and $1 million for the years ended December 31, 2012, 2011, and 2010, respectively. The ineffective portion of the change in the value of Entergy's cash flow hedges for 2009 was insignificant. is recorded in competitive businesses operating revenues.
Certain of the agreements to sell the power produced by Entergy's Non-Utility NuclearEntergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide collateral to secure its obligations when the current market prices exceed the contracted power prices. The primary form of collateral to satisfy these requirements is an Entergy Corporation guaranty.guarantee. As of December 31, 2009,2012, hedge contracts with one counterpartytwo counterparties were in a liability position (approximately $2 million total), but were significantly below the amountsamount of guaranteesthe guarantee provided under their contractsthe contract and no cash collateral was required. As of December 31, 2011, there were no hedge contracts with counterparties in a liability position. If the Entergy Corporation credit rating falls below investment grade, the impacteffect of the corporate guarantee is ignored and Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date. Entergy may effectively liquidate a cash flow hedge instrument by entering into a contract offsetting the original hedge, and then de-designating the original hedge in this situation. Gains or losses accumulated in other comprehensive income prior to de-designation continue to be deferred in other comprehensive income until they are included in income as the original hedged transaction occurs. From the point of de-designation, the gains or losses on the original hedge and the offsetting contract are recorded as assets or liabilities on the balance sheet and offset as they flow through to earnings.
Natural gas over-the-counter swaps that financially settle against NYMEX futures are used to manage fuel price riskvolatility for the Utility'sUtility’s Louisiana and Mississippi customers. All benefits or costs of the program are recorded in fuel costs. The total volume of natural gas swaps outstanding as of December 31, 20092012 is 36,710,00039,380,000 MMBtu for Entergy, 9,530,00012,670,000 MMBtu for Entergy Gulf States Louisiana, 15,590,00016,300,000 MMBtu for Entergy Louisiana, 10,480,000and 10,410,000 MMBtu for Entergy Mississippi, and 1,110,000 MMBtu for Entergy New Orleans.Mississippi. Credit support for these natural gas swaps areis covered by master agreements that do not require collateralization based on mark-to-market value, but do carry material adverse change clausesadequate assurance language that may lead to collateralization requests.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effect of Entergy'sEntergy’s derivative instruments not designated as hedging instruments on the consolidated income statements of income for the yearyears ended December 31, 20092012, 2011, and 2010 is as follows:
Instrument | | Amount of gain Statement of Income Locationrecognized in AOCI
| | Income Statement location | | Amount of gain (loss) recorded in income |
| | | | | | | |
| 2012 | | | | | | |
| Natural gas swaps | | - | | Fuel, fuel-related expenses, and gas purchased for resale | | ($42) million |
| Electricity swaps and options de-designated as hedged items | | $1 million | | Competitive businesses operating revenues | | $1 million |
| | | | | | |
| 2011 | | | | | | |
| Natural gas swaps | | - | | Fuel, fuel-related expenses, and gas purchased for resale | | ($160)62) million |
| Electricity swaps and options de-designated as hedged items | | $1 million | | Competitive businesses operating revenues | | $11 million |
| | | | | | |
| 2010 | | | | | | |
| Natural gas swaps | | - | | Fuel, fuel-related expenses, and gas purchased for resale | | ($95) million |
| Electricity swaps and options de-designated as hedged items | | $15 million | | Competitive businesses operating revenues | | $- |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Due to regulatory treatment, the natural gas swaps are marked to market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as an offsetting regulatory assetsasset or liabilities.liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through each Registrant's fuel cost recovery mechanism.mechanisms.
The fair values of the Registrant Subsidiaries'Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 20092012 and 2011 are as follows:
| Instrument | | Balance Sheet Location | | Fair Value | | Registrant |
Derivatives not designated as hedging instruments | | | | | | |
Assets: | | | | | | |
| 2012 | | | | | | |
| Liabilities: | | | | | | |
| Natural gas swaps | | Prepayments and otherGas hedge contracts | | $2.12.6 million | | Entergy Gulf States Louisiana |
| Natural gas swaps | | Gas hedge contracts | | $3.4 million | | Entergy Louisiana |
| Natural gas swaps | | Gas hedge contractsOther current liabilities | | $2.92.2 million | | Entergy Mississippi |
| | | | | | | |
| 2011 | | | | | | |
| Liabilities: | | | | | | |
| Natural gas swaps | | Gas hedge contracts | | $8.6 million | | Entergy Gulf States Louisiana |
| Natural gas swaps | | Gas hedge contracts | | $12.4 million | | Entergy Louisiana |
| Natural gas swaps | | Other current liabilities | | $7.8 million | | Entergy Mississippi |
| Natural gas swaps | | Other current liabilities | | $1.5 million | | Entergy New Orleans |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effects of the Registrant Subsidiaries'Subsidiaries’ derivative instruments not designated as hedging instruments on their statements of income for the yearyears ended December 31, 20092012, 2011, and 2010 are as follows:
Instrument | | Statement of Income Location | | Amount of gain (loss) loss
recorded in income | | Registrant |
| | | | | | | |
| 2012 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($42.0)12.9) million | | Entergy Gulf States Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($16.2) million | | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($11.2) million | | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($1.5) million | | Entergy New Orleans |
| 2011 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($66.4)17.9) million | | Entergy Gulf States Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($25.6) million | | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($15.0) million | | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($3.2) million | | Entergy New Orleans |
| 2010 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($40.7)25.0) million | | Entergy Mississippi |
| | | | | | Gulf States Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($10.5)40.5) million | | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($27.5) million | | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($1.7) million | | Entergy New Orleans |
Due to regulatory treatment, the natural gas swaps are marked to market through fuel, fuel-related expenses, and gas purchased for resale and then such amounts are simultaneously reversed and recorded as offsetting regulatory assets or liabilities. The gains or losses recorded as fuel expenses when the swaps are settled are recovered through each Registrant's fuel recovery mechanism.
Fair Values
The estimated fair values of Entergy'sEntergy’s financial instruments and derivatives are determined using bid prices, market quotes, and market quotes.financial modeling. Considerable judgment is required in developing the estimates of fair value. Therefore, estimates are not necessarily indicative of the amounts that Entergy could realize in a current market exchange. Gains or losses realized on financial instruments other than those instruments held by regulated businesses may bethe Entergy Wholesale Commodities business are reflected in future rates and therefore do not accrue to the benefit or detriment of shareholders. Entergy considers the carrying amounts of most financial instruments classified as current assets and liabilities to be a reasonable estimate of their fair value because of the short maturity of these instruments.
Accounting standards define fair value as an exit price, or the price that would be received to sell an asset or the amount that would be paid to transfer a liability in an orderly transaction between knowledgeable market participants at the date of measurement. Entergy and the Registrant Subsidiaries use assumptions or market input data that market participants would use in pricing assets or liabilities at fair value. The inputs can be readily observable, corroborated by market data, or generally unobservable. Entergy and the Registrant Subsidiaries endeavor to use the best available information to determine fair value.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Accounting standards establish a fair value hierarchy that prioritizes the inputs used to measure fair value. The hierarchy establishes the highest priority for unadjusted market quotes in an active market for the identical asset or liability and the lowest priority for unobservable inputs. The three levels of the fair value hierarchy are:
| · | Level 1 - Level 1 inputs are unadjusted quoted prices in active markets for identical assets or liabilities that the entity has the ability to access at the measurement date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of individually owned common stocks, cash equivalents (temporary cash investments, securitization recovery trust account, and escrow accounts), debt instruments, and gas hedge contracts,contracts. See Note 1 to the securitization trust recovery account,financial statements for a discussion of cash and storm reserve escrow accounts.cash equivalents. |
| · | Level 2 - Level 2 inputs are inputs other than quoted prices included in Level 1 that are, either directly or indirectly, observable for the asset or liability at the measurement date. Assets are valued based on prices derived by independent third parties that use inputs such as benchmark yields, reported trades, broker/dealer quotes, and issuer spreads. Prices are reviewed and can be challenged with the independent parties and/or overridden by Entergy if it is believed such would be more reflective of fair value. Level 2 inputs include the following: |
| - | quoted prices for similar assets or liabilities in active markets; |
| - | quoted prices for identical assets or liabilities in inactive markets; |
| - | inputs other than quoted prices that are observable for the asset or liability; or |
| - | inputs that are derived principally from or corroborated by observable market data by correlation or other means. |
Level 2 consists primarily of individually ownedindividually-owned debt instruments or shares in common trusts. Common trust funds are stated at estimated fair value based on the fair market value of the underlying investments.
| · | Level 3 - Level 3 inputs are pricing inputs that are generally less observable or unobservable from objective sources. These inputs are used with internally developed methodologies to produce management'smanagement’s best estimate of fair value for the asset or liability. Level 3 consists primarily of derivative power contracts used as cash flow hedges of power sales at merchant power plants. |
The values for the cash flow hedges that are recorded as derivativepower contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as model-generated prices for longer-term marketsimplied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Entergy Wholesale Commodities Risk Control group and sent to the Entergy Wholesale Commodities Back Office and Entergy Nuclear Finance groups for evaluation. The primary functions of the Entergy Wholesale Commodities Risk Control Group include: gathering, validating and reporting market data, providing market and credit risk analyses and valuations in support of Entergy Wholesale Commodities’ commercial transactions, developing and administering protocols for the management of market and credit risks, implementing and maintaining controls around changes to market data in the energy trading and risk management system, reviewing creditworthiness of counterparties, supporting contract negotiations with new counterparties, administering credit support for contracts, and managing the daily margining process. The primary functions of the Entergy Wholesale Commodities Back Office are managing the energy trading and risk management system, forecasting revenues, forward positions and analysis, performing contract administration, market and counterparty settlements and revenue reporting and analysis along with maintaining related controls for Entergy Wholesale Commodities. Both Entergy Wholesale Commodities Risk Control and Entergy Wholesale Commodities Back Office report to the Entergy Wholesale Commodities VP, Finance & Risk Group. Entergy Nuclear Finance is primarily responsible for the financial planning of Entergy’s utility and non-utility nuclear businesses and has a significant role in accounting for the activities and transactions of the associated companies. The VP, Chief Financial Officer – Nuclear Operations within Entergy Nuclear Finance reports to the Chief Accounting Officer.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The amounts reflected as the fair value of derivative assets or liabilitieselectricity swaps are based on the estimated amount that the contracts are in-the-money at the balance sheet date (treated as an asset) or out-of-the-money at the balance sheet date (treated as a liability) and would equal the estimated amount receivable or payable by Entergy if the contracts were settled at that date. These derivative contracts include cash flow hedges that swap fixed for floating cash flows for sales of the output from Entergy's Non-Utility Nuclearthe Entergy Wholesale Commodities business. The fair values are based on the mark-to-market comparison between the fixed contract prices and the floating prices determined each period from a combination of quoted forward power market prices for the period for which such curves are available, and model-generated prices using quoted forward gas market curves and estimates regarding heat rates to convert gas to power and the costs associated with the transportation of the power from the plants' bus bar to the contract's point of delivery, generally a power market hub, for the period thereafter.prices. The differencedifferences between the fixed price in the swap contract and these market-related prices multiplied by the volume specified in the contract and discounted at the counterparties'counterparties’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities. $202 millionFor contracts that have unit contingent terms, a further discount is applied based on the historical relationship between contract and market prices for similar contract terms.
The amounts reflected as the fair values of cash flow hedges aselectricity options are valued based on a Black Scholes model, and are calculated at the end of each month for accounting purposes. Inputs to the valuation include end of day forward market prices for the period when the transactions will settle, implied volatilities based on market volatilities provided by a third party data aggregator, and US Treasury rates for a risk-free return rate. As described further below, prices and implied volatilities are reviewed and can be adjusted if it is determined that there is a better representation of fair value. As of December 31, 2009 are2012, Entergy had in-the-money derivative contracts with a fair value of $180 million with counterparties or their guarantor who are all currently investment grade. $2 million of the cash flow hedgesderivative contracts as of December 31, 20092012 are out-of-the-money contracts supported by corporate guarantees, which would require additional cash or letters of credit in the event of a decrease in Entergy Corporation’s credit rating to below investment grade.
On a daily basis, Entergy Wholesale Commodities calculates the mark-to-market for all derivative transactions. Entergy Wholesale Commodities Risk Control Group also validates forward market prices by comparing them to settlement prices of actual market transactions. Significant differences are analyzed and potentially adjusted based on actual transaction clearing prices, or a methodology that considers natural gas prices and market heat rates. Implied volatilities used to value options are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions. Moreover, on at least a monthly basis the Office of Corporate Risk Oversight confirms the mark-to-market calculations and prepares price scenarios and credit downgrade scenario analysis. The scenario analysis is communicated to senior management within Entergy and within Entergy Wholesale Commodities. Finally, for all proposed derivative transactions an analysis is completed to assess the risk of adding the proposed derivative to Entergy Wholesale Commodities’ portfolio. In particular, the credit, liquidity, and financial metrics impacts are calculated for this analysis. This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following tables set forth, by level within the fair value hierarchy, Entergy'sEntergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 20092012 and 2008.December 31, 2011. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect their placement within the fair value hierarchy levels.
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $420 | | $- | | $- | | $420 |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 358 | | 2,101 | | - | | 2,459 |
| Debt securities | | 769 | | 962 | | - | | 1,731 |
| Power contracts | | - | | - | | 191 | | 191 |
| Securitization recovery trust account | | 46 | | - | | - | | 46 |
| Escrow accounts | | 386 | | - | | - | | 386 |
| | | $1,979 | | $3,063 | | $191 | | $5,233 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Power contracts | | $- | | $- | | $13 | | $13 |
| Gas hedge contracts | | 8 | | - | | - | | 8 |
| | | $8 | | $- | | $13 | | $21 |
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $613 | | $- | | $- | | $613 |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 397 | | 1,732 | | - | | 2,129 |
| Debt securities | | 639 | | 1,020 | | - | | 1,659 |
| Power contracts | | - | | - | | 312 | | 312 |
| Securitization recovery trust account | | 50 | | - | | - | | 50 |
| Escrow accounts | | 335 | | - | | - | | 335 |
| | | $2,034 | | $2,752 | | $312 | | $5,098 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $30 | | $- | | $- | | $30 |
| (a) | The decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 17 for additional information on the investment portfolios. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| 2009 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $1,624 | | $- | | $- | | $1,624 |
| Decommissioning trust funds: | | | | | | | | |
| Equity securities | | 528 | | 1,260 | | - | | 1,788 |
| Debt securities | | 443 | | 980 | | - | | 1,423 |
| Power contracts | | - | | - | | 200 | | 200 |
| Securitization recovery trust account | | 13 | | - | | - | | 13 |
| Gas hedge contracts | | 8 | | - | | - | | 8 |
| Other investments | | 42 | | - | | - | | 42 |
| | | $2,658 | | $2,240 | | $200 | | $5,098 |
| 2008 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $1,805 | | $- | | $- | | $1,805 |
| Decommissioning trust funds | | 508 | | 2,324 | | - | | 2,832 |
| Power contracts | | - | | - | | 207 | | 207 |
| Securitization recovery trust account | | 12 | | - | | - | | 12 |
| Other investments | | 35 | | - | | - | | 35 |
| | | $2,360 | | $2,324 | | $207 | | $4,891 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $67 | | $- | | $- | | $67 |
The following table sets forth a reconciliation of changes in the net assets (liabilities) for the fair value of derivatives classified as Level 3 in the fair value hierarchy for the years ended December 31, 20092012, 2011, and 2008:2010:
| | | 2009 | | 2008 | | 2012 | | 2011 | | 2010 |
| | | (In Millions) | | (In Millions) |
| | | | | | | | | | | |
| Balance as of January 1, | | $207 | | ($12) | | $312 | | $197 | | $200 |
| | | | | | | | | | | |
| Price changes (unrealized gains/losses) | | 315 | | 156 | |
| Settlements | | (322) | | 63 | |
| Unrealized gains from price changes | | | 139 | | 274 | | 220 |
| Unrealized gains (losses) on originations | | | 9 | | 15 | | (4) |
| Realized gains (losses) included in earnings | | | (14) | | (6) | | 1 |
| Realized gains on settlements | | | (268) | | (168) | | (220) |
| | | | | | | | | | | |
| Balance as of December 31, | | $200 | | $207 | | $178 | | $312 | | $197 |
The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy, and the valuation techniques and significant unobservable inputs to each which cause that classification, as of December 31, 2012:
Transaction Type | | Fair Value as of December 31, 2012 | | Significant Unobservable Inputs | | Range from Average % | | Effect on Fair Value |
| | | | | | | | |
| Electricity swaps | | $104 million | | Unit contingent discount | | +/-3% | | $5 million |
| Electricity options | | $74 million | | Implied volatility | | +/-21% | | $37 million |
The following table sets forth an analysis of each of the types of unobservable inputs impacting the fair value of items classified as Level 3 within the fair value hierarchy, and the sensitivity to changes to those inputs:
Significant Unobservable Input | | Transaction Type | | Position | | Change to Input | | Effect on Fair Value |
| | | | | | | | |
| Unit contingent discount | | Electricity swaps | | Sell | | Increase (Decrease) | | Decrease (Increase) |
| Implied volatility | | Electricity options | | Sell | | Increase (Decrease) | | Increase (Decrease) |
| Implied volatility | | Electricity options | | Buy | | Increase (Decrease) | | Increase (Decrease) |
The following table sets forth, by level within the fair value hierarchy, the Registrant Subsidiaries'Subsidiaries’ assets that are accounted for at fair value on a recurring basis as of December 31, 20092012 and 2008.December 31, 2011. The assessment of the significance of a particular input to a fair value measurement requires judgment and may affect its placement within the fair value hierarchy levels.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| 2012 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | Level 1 | | Level 2 | | Level 3 | | Total | | (In Millions) |
| | | (In Millions) | |
| 2009 | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $82.9 | | $- | | $- | | $82.9 | | $24.9 | | $- | | $- | | $24.9 |
| Decommissioning trust funds: | | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | | |
| Equity securities | | 15.4 | | 205.3 | | - | | 220.7 | | 9.5 | | 374.5 | | - | | 384.0 |
| Debt securities | | 17.6 | | 201.9 | | - | | 219.5 | | 94.3 | | 122.3 | | - | | 216.6 |
| Securitization recovery trust account | | | 4.4 | | - | | - | | 4.4 |
| Escrow accounts | | | 38.0 | | - | | - | | 38.0 |
| | | $115.9 | | $407.2 | | $- | | $523.1 | | $171.1 | | $496.8 | | $- | | $667.9 |
| 2008 | | | |
| 2011 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $36.3 | | $- | | $- | | $36.3 | | $17.9 | | $- | | $- | | $17.9 |
| Decommissioning trust funds | | 16.4 | | 374.1 | | - | | 390.5 | |
| Decommissioning trust funds (a): | | | | | | | | | |
| Equity securities | | | 6.3 | | 323.1 | | - | | 329.4 |
| Debt securities | | | 82.8 | | 129.5 | | - | | 212.3 |
| Securitization recovery trust account | | | 3.9 | | - | | - | | 3.9 |
| | | $52.7 | | $374.1 | | $- | | $426.8 | | $110.9 | | $452.6 | | $- | | $563.5 |
Entergy Gulf States Louisiana
| 2012 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | Level 1 | | Level 2 | | Level 3 | | Total | | (In Millions) |
| 2009 | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $144.3 | | $- | | $- | | $144.3 | | $0.6 | | $- | | $- | | $0.6 |
| Decommissioning trust funds: | | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | | |
| Equity securities | | 6.7 | | 175.5 | | - | | 182.2 | | 5.5 | | 283.0 | | - | | 288.5 |
| Debt securities | | 25.3 | | 142.0 | | - | | 167.3 | | 49.5 | | 139.4 | | - | | 188.9 |
| Escrow accounts | | | 87.0 | | - | | - | | 87.0 |
| | | | $142.6 | | $422.4 | | $- | | $565.0 |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Gas hedge contracts | | 2.1 | | - | | - | | 2.1 | | $2.6 | | $- | | $- | | $2.6 |
| | | $178.4 | | $317.5 | | $- | | $495.9 | |
| 2008 | | | | | | | | | |
| 2011 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $26.6 | | $- | | $- | | $26.6 | | $24.6 | | $- | | $- | | $24.6 |
| Decommissioning trust funds | | 22.3 | | 280.9 | | - | | 303.2 | |
| Decommissioning trust funds (a): | | | | | | | | | |
| Equity securities | | | 5.1 | | 233.6 | | - | | 238.7 |
| Debt securities | | | 39.5 | | 142.7 | | - | | 182.2 |
| Escrow accounts | | | 90.2 | | - | | - | | 90.2 |
| | | $48.9 | | $280.9 | | $- | | $329.8 | | $159.4 | | $376.3 | | $- | | $535.7 |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Gas hedge contracts | | $20.2 | | $- | | $- | | $20.2 | | $8.6 | | $- | | $- | | $8.6 |
| | | | | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
| 2012 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | Level 1 | | Level 2 | | Level 3 | | Total | | (In Millions) |
| 2009 | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $151.7 | | $- | | $- | | $151.7 | | $29.3 | | $- | | $- | | $29.3 |
| Decommissioning trust funds: | | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | | |
| Equity securities | | 7.0 | | 110.9 | | - | | 117.9 | | 2.0 | | 173.5 | | - | | 175.5 |
| Debt securities | | 44.3 | | 46.9 | | - | | 91.2 | | 52.6 | | 59.3 | | - | | 111.9 |
| Gas hedge contracts | | 3.4 | | - | | - | | 3.4 | |
| Other investments | | 0.8 | | - | | - | | 0.8 | |
| Securitization recovery trust account | | | 4.4 | | - | | - | | 4.4 |
| Escrow accounts | | | 187.0 | | - | | - | | 187.0 |
| | | $207.2 | | $157.8 | | $- | | $365.0 | | $275.3 | | $232.8 | | $- | | $508.1 |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Gas hedge contracts | | | $3.4 | | $- | | $- | | $3.4 |
| 2008 | | | | | | | | |
| Assets: | | | | | | | | |
| Temporary cash investments | | $138.9 | | $- | | $- | | $138.9 |
| Decommissioning trust funds | | 51.0 | | 129.9 | | - | | 180.9 |
| Other investments | | 0.8 | | - | | - | | 0.8 |
| | | $190.7 | | $129.9 | | $- | | $320.6 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $26.7 | | $- | | $- | | $26.7 |
| | | | | | | | | |
| | | | | | | | | |
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | $2.9 | | $146.3 | | $- | | $149.2 |
| Debt securities | | 51.6 | | 53.2 | | - | | 104.8 |
| Securitization recovery trust account | | 5.2 | | - | | - | | 5.2 |
| Escrow accounts | | 201.2 | | - | | - | | 201.2 |
| | | $260.9 | | $199.5 | | $- | | $460.4 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $12.4 | | $- | | $- | | $12.4 |
Entergy Mississippi
| | Level 1 | | Level 2 | | Level 3 | | Total |
| 2009 | | | | | | | | | |
| 2012 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | $90.3 | | $- | | $- | | $90.3 | | $52.4 | | $- | | $- | | $52.4 |
| Escrow accounts | | | 61.8 | | - | | - | | 61.8 |
| | | | $114.2 | | $- | | $- | | $114.2 |
| | | | | | | | | | |
| Liabilities: | | | | | | | | | |
| Gas hedge contracts | | 2.9 | | - | | - | | 2.9 | | $2.2 | | $- | | $- | | $2.2 |
| Other investments | | 31.9 | | - | | - | | 31.9 | |
| | | $125.1 | | $- | | $- | | $125.1 | |
| 2008 | | | | | | | | | |
| 2011 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | | | | | | | | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Other investments | | $31.7 | | $- | | $- | | $31.7 | |
| Escrow accounts | | | $31.8 | | $- | | $- | | $31.8 |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Gas hedge contracts | | $15.6 | | $- | | $- | | $15.6 | | $7.8 | | $- | | $- | | $7.8 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $9.1 | | $- | | $- | | $9.1 |
| Escrow accounts | | 10.6 | | - | | - | | 10.6 |
| | | $19.7 | | $- | | $- | | $19.7 |
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $9.3 | | $- | | $- | | $9.3 |
| Escrow accounts | | 12.0 | | - | | - | | 12.0 |
| | | $21.3 | | $- | | $- | | $21.3 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $1.5 | | $- | | $- | | $1.5 |
Entergy Texas
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Temporary cash investments | | $59.7 | | $- | | $- | | $59.7 |
| Securitization recovery trust account | | 37.3 | | - | | - | | 37.3 |
| | | $97.0 | | $- | | $- | | $97.0 |
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Temporary cash investments | | $65.1 | | $- | | $- | | $65.1 |
| Securitization recovery trust account | | 41.2 | | - | | - | | 41.2 |
| | | $106.3 | | $- | | $- | | $106.3 |
System Energy
| 2012 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $83.5 | | $- | | $- | | $83.5 |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 1.6 | | 282.0 | | - | | 283.6 |
| Debt securities | | 141.1 | | 65.9 | | - | | 207.0 |
| | | $226.2 | | $347.9 | | $- | | $574.1 |
| 2011 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | | $154.2 | | $- | | $- | | $154.2 |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 2.7 | | 234.5 | | - | | 237.2 |
| Debt securities | | 123.2 | | 63.0 | | - | | 186.2 |
| | | $280.1 | | $297.5 | | $- | | $577.6 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans
| | | Level 1 | | Level 2 | | Level 3 | | Total |
| 2009 | | | | | | | | |
| Assets: | | | | | | | | |
| Temporary cash investments | | $190.0 | | $- | | $- | | $190.0 |
| Other investments | | 9.5 | | - | | - | | 9.5 |
| | | $199.5 | | $- | | $- | | $199.5 |
| 2008 | | | | | | | | |
| Assets: | | | | | | | | |
| Other investments | | $2.8 | | $- | | $- | | $2.8 |
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | | $4.3 | | $- | | $- | | $4.3 |
| | | | | | | | | |
Entergy Texas
| (a) | | Level 1 | | Level 2 | | Level 3 | | Total |
| 2009 | | | | | | | | |
| Assets: | | | | | | | | |
| Temporary cash investments | | $199.2 | | $- | | $- | | $199.2 |
| Securitization recovery trust account | | 13.1 | | - | | - | | 13.1 |
| | | $212.3 | | $- | | $- | | $212.3 |
| 2008 | | | | | | | | |
| Assets: | | | | | | | | |
| Securitization recovery trust account | | $12.0 | | $- | | $- | | $12.0 |
System Energy
| | Level 1 | | Level 2 | | Level 3 | | TotalThe decommissioning trust funds hold equity and fixed income securities. Equity securities are invested to approximate the returns of major market indices. Fixed income securities are held in various governmental and corporate securities. See Note 17 for additional information on the investment portfolios. |
2009 Assets: | | | | | | | | |
| Temporary cash investments | | $263.6 | | $- | | $- | | $263.6 |
| Decommissioning trust funds: | | | | | | | | |
| Equity securities | | 2.1 | | 180.2 | | - | | 182.3 |
| Debt securities | | 78.4 | | 66.3 | | - | | 144.7 |
| | | $344.1 | | $246.5 | | $- | | $590.6 |
| 2008 | | | | | | | | |
| Assets: | | | | | | | | |
| Temporary cash investments | | $102.5 | | $- | | $- | | $102.5 |
| Decommissioning trust funds | | 69.5 | | 199.3 | | - | | 268.8 |
| | | $172.0 | | $199.3 | | $- | | $371.3 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 17. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)
Entergy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The NRC requires Entergy subsidiaries to maintain trusts to fund the costs of decommissioning ANO 1, ANO 2, River Bend, Waterford 3, Grand Gulf, Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick). The funds are invested primarily in equity securities;securities, fixed-rate fixed-income securities;securities, and cash and cash equivalents.
Entergy records decommissioning trust funds on the balance sheet at their fair value. Because of the ability of the Registrant Subsidiaries to recover decommissioning costs in rates and in accordance with the regulatory treatment for decommissioning trust funds, the Registrant Subsidiaries have recorded an offsetting amount of unrealized gains/(losses) on investment securities in other regulatory liabilities/assets. For the nonregulated portion of River Bend, Entergy Gulf States Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades do not meet the criteria for regulatory accounting treatment. Accordingly, unrealized gains recorded on the assets in these trust funds are recognized in the accumulated other comprehensive income component of shareholders'shareholders’ equity because these assets are classified as available for sale. Unrealized losses (where cost exceeds fair market value) on the assets in these trust funds are also recorded in the accumulated other comprehensive income component of shareholders'shareholders’ equity unless the unrealized loss is other than temporary and therefore recorded in earnings. Effective January 1, 2009,Generally, Entergy adoptedrecords realized gains and losses on its debt and equity securities using the specific identification method to determine the cost basis of its securities.
The securities held as of December 31, 2012 and 2011 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| | | | | | | |
| 2012 | | | | | | |
| Equity Securities | | $2,459 | | $662 | | $1 |
| Debt Securities | | 1,731 | | 116 | | 5 |
| Total | | $4,190 | | $778 | | $6 |
| | | | | | | |
| 2011 | | | | | | |
| Equity Securities | | $2,129 | | $423 | | $14 |
| Debt Securities | | 1,659 | | 115 | | 5 |
| Total | | $3,788 | | $538 | | $19 |
Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income for the decommissioning trusts which do not meet the criteria for regulatory accounting treatment as described above. Unrealized gains/(losses) above are reported before deferred taxes of $211 million and $149 million as of December 31, 2012 and 2011, respectively. The amortized cost of debt securities was $1,637 million as of December 31, 2012 and $1,530 million as of December 31, 2011. As of December 31, 2012, the debt securities
Entergy Corporation and Subsidiaries
Notes to Financial Statements
have an accounting pronouncement providing guidance regarding recognitionaverage coupon rate of approximately 3.78%, an average duration of approximately 5.43 years, and presentationan average maturity of approximately 8.50 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor’s 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2012:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $37 | | $1 | | $175 | | $1 |
| More than 12 months | | 20 | | - | | 48 | | 4 |
| Total | | $57 | | $1 | | $223 | | $5 |
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2011:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $130 | | $9 | | $123 | | $3 |
| More than 12 months | | 43 | | 5 | | 60 | | 2 |
| Total | | $173 | | $14 | | $183 | | $5 |
The unrealized losses in excess of twelve months on equity securities above relate to Entergy’s Utility operating companies and System Energy.
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | 2011 |
| | | (In Millions) |
| less than 1 year | | $53 | | $69 |
| 1 year - 5 years | | 681 | | 566 |
| 5 years - 10 years | | 562 | | 583 |
| 10 years - 15 years | | 164 | | 187 |
| 15 years - 20 years | | 61 | | 42 |
| 20 years+ | | 210 | | 212 |
| Total | | $1,731 | | $1,659 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
During the years ended December 31, 2012, 2011, and 2010, proceeds from the dispositions of securities amounted to $2,074 million, $1,360 million, and $2,606 million, respectively. During the years ended December 31, 2012, 2011, and 2010, gross gains of $39 million, $29 million, and $69 million, respectively, and gross losses of $7 million, $11 million, and $9 million, respectively, were reclassified out of other comprehensive income into earnings.
Entergy Arkansas
Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2012 and 2011 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2012 | | | | | | |
| Equity Securities | | $384.0 | | $116.1 | | $- |
| Debt Securities | | 216.6 | | 14.5 | | 0.2 |
Total | | $600.6 | | $130.6 | | $0.2 |
| | | | | | | |
| 2011 | | | | | | |
| Equity Securities | | $329.4 | | $70.9 | | $0.4 |
| Debt Securities | | 212.3 | | 15.2 | | 0.4 |
Total | | $541.7 | | $86.1 | | $0.8 |
The amortized cost of debt securities was $202.3 million as of December 31, 2012 and $197.5 million as of December 31, 2011. As of December 31, 2012, the debt securities have an average coupon rate of approximately 3.24%, an average duration of approximately 5.28 years, and an average maturity of approximately 6.15 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2012:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $0.2 | | $- | | $24.4 | | $0.2 |
| More than 12 months | | - | | - | | 1.0 | | - |
Total | | $0.2 | | $- | | $25.4 | | $0.2 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2011:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $13.7 | | $0.4 | | $14.3 | | $0.4 |
| More than 12 months | | - | | - | | 1.0 | | - |
Total | | $13.7 | | $0.4 | | $15.3 | | $0.4 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | 2011 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $8.8 | | $7.8 |
| 1 year - 5 years | | 98.6 | | 86.5 |
| 5 years - 10 years | | 93.1 | | 109.1 |
| 10 years - 15 years | | 5.1 | | 2.7 |
| 20 years+ | | 11.0 | | 6.2 |
Total | | $216.6 | | $212.3 |
During the years ended December 31, 2012, 2011, and 2010, proceeds from the dispositions of securities amounted to $144.3 million, $125.4 million, and $367.3 million, respectively. During the years ended December 31, 2012, 2011, and 2010, gross gains of $3.4 million, $3.9 million, and $29.2 million, respectively, and gross losses of $0.1 million, $0.2 million, and $0.8 million, respectively, were recorded in earnings.
Entergy Gulf States Louisiana
Entergy Gulf States Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2012 and 2011 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2012 | | | | | | |
| Equity Securities | | $288.5 | | $69.8 | | $- |
| Debt Securities | | 188.9 | | 15.8 | | 0.1 |
Total | | $477.4 | | $85.6 | | $0.1 |
| | | | | | | |
| 2011 | | | | | | |
| Equity Securities | | $238.7 | | $40.9 | | $0.8 |
| Debt Securities | | 182.2 | | 15.2 | | 0.3 |
Total | | $420.9 | | $56.1 | | $1.1 |
| | | | | | | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The amortized cost of debt securities was $174.1 million as of December 31, 2012 and $166.9 million as of December 31, 2011. As of December 31, 2012, the debt securities have an average coupon rate of approximately 4.74%, an average duration of approximately 5.58 years, and an average maturity of approximately 8.70 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2012:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $1.2 | | $- | | $9.1 | | $0.1 |
| More than 12 months | | 1.0 | | - | | - | | - |
| Total | | $2.2 | | $- | | $9.1 | | $0.1 |
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2011:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $14.0 | | $0.5 | | $9.3 | | $0.2 |
| More than 12 months | | 2.7 | | 0.3 | | 1.1 | | 0.1 |
| Total | | $16.7 | | $0.8 | | $10.4 | | $0.3 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | 2011 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $8.0 | | $7.1 |
| 1 year - 5 years | | 43.5 | | 40.8 |
| 5 years - 10 years | | 63.5 | | 53.5 |
| 10 years - 15 years | | 55.8 | | 62.9 |
| 15 years - 20 years | | 8.5 | | 3.2 |
| 20 years+ | | 9.6 | | 14.7 |
| Total | | $188.9 | | $182.2 |
During the years ended December 31, 2012, 2011, and 2010, proceeds from the dispositions of securities amounted to $131.0 million, $76.8 million, and $100.8 million, respectively. During the years ended December 31, 2012, 2011, and 2010, gross gains of $6.7 million, $2.8 million, and $2.0 million, respectively, and gross losses of $0.04 million, $0.5 million, and $0.4 million, respectively, were recorded in earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2012 and 2011 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2012 | | | | | | |
| Equity Securities | | $175.5 | | $48.9 | | $0.1 |
| Debt Securities | | 111.9 | | 9.4 | | 0.1 |
Total | | $287.4 | | $58.3 | | $0.2 |
| | | | | | | |
| 2011 | | | | | | |
| Equity Securities | | $149.2 | | $29.7 | | $1.6 |
| Debt Securities | | 104.8 | | 8.8 | | 0.2 |
Total | | $254.0 | | $38.5 | | $1.8 |
The amortized cost of debt securities was $102.6 million as of December 31, 2012 and $91.9 million as of December 31, 2011. As of December 31, 2012, the debt securities have an average coupon rate of approximately 3.64%, an average duration of approximately 5.38 years, and an average maturity of approximately 9.39 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2012:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $0.7 | | $- | | $3.4 | | $- |
| More than 12 months | | 5.6 | | 0.1 | | 0.5 | | 0.1 |
| Total | | $6.3 | | $0.1 | | $3.9 | | $0.1 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2011:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $11.6 | | $0.3 | | $5.5 | | $0.2 |
| More than 12 months | | 10.0 | | 1.3 | | 0.2 | | - |
| Total | | $21.6 | | $1.6 | | $5.7 | | $0.2 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | 2011 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $1.9 | | $3.9 |
| 1 year - 5 years | | 42.3 | | 39.8 |
| 5 years - 10 years | | 24.9 | | 22.2 |
| 10 years - 15 years | | 18.8 | | 18.9 |
| 15 years - 20 years | | 1.7 | | 2.2 |
| 20 years+ | | 22.3 | | 17.8 |
| Total | | $111.9 | | $104.8 |
During the years ended December 31, 2012, 2011, and 2010, proceeds from the dispositions of securities amounted to $27.6 million, $19.9 million, and $44.5 million, respectively. During the years ended December 31, 2012, 2011, and 2010, gross gains of $0.2 million, $0.3 million, and $0.7 million, respectively, and gross losses of $0.04 million, $0.2 million, and $0.3 million, respectively, were recorded in earnings.
System Energy
System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2012 and 2011 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2012 | | | | | | |
| Equity Securities | | $283.6 | | $63.6 | | $0.2 |
| Debt Securities | | 207.0 | | 9.3 | | 0.1 |
Total | | $490.6 | | $72.9 | | $0.3 |
| | | | | | | |
| 2011 | | | | | | |
| Equity Securities | | $237.2 | | $35.4 | | $5.4 |
| Debt Securities | | 186.2 | | 9.5 | | 0.1 |
Total | | $423.4 | | $44.9 | | $5.5 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The amortized cost of debt securities was $197.8 million as of December 31, 2012 and $175.1 million as of December 31, 2011. As of December 31, 2012, the debt securities have an average coupon rate of approximately 2.60%, an average duration of approximately 4.52 years, and an average maturity of approximately 6.13 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor’s 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2012:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $1.4 | | $- | | $15.5 | | $0.1 |
| More than 12 months | | 13.0 | | 0.2 | | - | | - |
| Total | | $14.4 | | $0.2 | | $15.5 | | $0.1 |
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2011:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $41.3 | | $1.8 | | $10.5 | | $0.1 |
| More than 12 months | | 30.0 | | 3.6 | | - | | - |
| Total | | $71.3 | | $5.4 | | $10.5 | | $0.1 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2012 and 2011 are as follows:
| | | 2012 | | 2011 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $1.3 | | $10.2 |
| 1 year - 5 years | | 128.7 | | 94.6 |
| 5 years - 10 years | | 53.9 | | 57.9 |
| 10 years - 15 years | | 2.3 | | 2.6 |
| 15 years - 20 years | | 1.4 | | 2.9 |
| 20 years+ | | 19.4 | | 18.0 |
| Total | | $207.0 | | $186.2 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
During the years ended December 31, 2012, 2011, and 2010, proceeds from the dispositions of securities amounted to $349.4 million, $203.4 million, and $322.8 million, respectively. During the years ended December 31, 2012, 2011, and 2010, gross gains of $3.6 million, $2.7 million, and $4.4 million, respectively, and gross losses of $0.3 million, $1.2 million, and $0.6 million, respectively, were recorded in earnings.
Other-than-temporary impairments and unrealized gains and losses
Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluate unrealized losses at the end of each period to determine whether an other-than-temporary impairments related to investments in debt securities.impairment has occurred. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). Entergy did not have any material other-than-temporary impairments relating to credit losses on debt securities for the years ended December 31, 2012, 2011, and 2010. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy'sEntergy’s trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments.
The securities held as of December 31, 2009 and 2008 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2009 | | | | | | |
| Equity Securities | | $1,788 | | $311 | | $30 |
| Debt Securities | | 1,423 | | 63 | | 8 |
| Total | | $3,211 | | $374 | | $38 |
| | | | | | | |
| | | | | | | |
| 2008 | | | | | | |
| Equity Securities | | $1,436 | | $85 | | $177 |
| Debt Securities | | 1,396 | | 77 | | 21 |
| Total | | $2,832 | | $162 | | $198 |
The amortized cost of debt securities was $1,368 million as of December 31, 2009 and $1,340 million as of December 31, 2008. As of December 31, 2009, the debt securities have an average coupon rate of approximately 4.68%, an average duration of approximately 5.08 years, and an average maturity of approximately 8.3 years. The equity securities are generally
Entergy Corporation and Subsidiaries
Notes to Financial Statements
held in funds that are designed to approximate or somewhat exceed the return of the Standard & Poor's 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index or the Russell 3000 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2009:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $57 | | $1 | | $311 | | $6 |
| More than 12 months | | 205 | | 29 | | 18 | | 2 |
| Total | | $262 | | $30 | | $329 | | $8 |
The unrealized losses in excess of twelve months above relate to Entergy's Utility operating companies and System Energy.
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2009 and 2008 are as follows:
| | | 2009 | | 2008 |
| | | (In Millions) |
| less than 1 year | | $31 | | $21 |
| 1 year - 5 years | | 676 | | 526 |
| 5 years - 10 years | | 388 | | 490 |
| 10 years - 15 years | | 131 | | 146 |
| 15 years - 20 years | | 34 | | 52 |
| 20 years+ | | 163 | | 161 |
| Total | | $1,423 | | $1,396 |
During the years ended December 31, 2009, 2008, and 2007, proceeds from the dispositions of securities amounted to $2,571 million, $1,652 million, and $1,583 million, respectively. During the years ended December 31, 2009, 2008, and 2007, gross gains of $80 million, $26 million, and $5 million, respectively, and gross losses of $30 million, $20 million, and $4 million, respectively, were reclassified out of other comprehensive income into earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
Entergy Arkansas holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2009 and 2008 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2009 | | | | | | |
| Equity Securities | | $220.7 | | $60.1 | | $3.4 |
| Debt Securities | | 219.5 | | 10.7 | | 1.7 |
Total | | $440.2 | | $70.8 | | $5.1 |
| | | | | | | |
| 2008 | | | | | | |
| Equity Securities | | $165.6 | | $31.7 | | $13.7 |
| Debt Securities | | 224.9 | | 12.8 | | 2.4 |
Total | | $390.5 | | $44.5 | | $16.1 |
The amortized cost of debt securities was $210.5 million as of December 31, 2009 and $214.5 million as of December 31, 2008. As of December 31, 2009, the debt securities have an average coupon rate of approximately 4.59%, an average duration of approximately 4.71 years, and an average maturity of approximately 5.8 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2009:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $- | | $- | | $31.9 | | $1.2 |
| More than 12 months | | 26.8 | | 3.4 | | 3.9 | | 0.5 |
Total | | $26.8 | | $3.4 | | $35.8 | | $1.7 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2009 and 2008 are as follows:
| | | 2009 | | 2008 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $6.7 | | $2.0 |
| 1 year - 5 years | | 133.2 | | 127.0 |
| 5 years - 10 years | | 68.2 | | 93.9 |
| 10 years - 15 years | | 5.1 | | 2.0 |
| 15 years - 20 years | | - | | - |
| 20 years+ | | 6.3 | | - |
Total | | $219.5 | | $224.9 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
During the years ended December 31, 2009, 2008, and 2007, proceeds from the dispositions of securities amounted to $154.6 million, $162.1 million, and $96.0 million, respectively. During the years ended December 31, 2009, 2008, and 2007, gross gains of $2.6 million, $3.8 million, and $0.4 million, respectively, and gross losses of $1.4 million, $0.5 million, and $0.4 million, respectively, were recorded in earnings.
Entergy Gulf States Louisiana
Entergy Gulf States Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2009 and 2008 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2009 | | | | | | |
| Equity Securities | | $182.2 | | $17.0 | | $5.3 |
| Debt Securities | | 167.3 | | 10.0 | | 0.9 |
| Total | | $349.5 | | $27.0 | | $6.2 |
| | | | | | | |
| 2008 | | | | | | |
| Equity Securities | | $132.3 | | $4.6 | | $24.5 |
| Debt Securities | | 170.9 | | 8.7 | | 3.3 |
| Total | | $303.2 | | $13.3 | | $27.8 |
The amortized cost of debt securities was $158.5 million as of December 31, 2009 and $165.5 million as of December 31, 2008. As of December 31, 2009, the debt securities have an average coupon rate of approximately 4.76%, an average duration of approximately 6.23 years, and an average maturity of approximately 9.6 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2009:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $- | | $- | | $24.7 | | $0.6 |
| More than 12 months | | 48.9 | | 5.3 | | 4.3 | | 0.3 |
| Total | | $48.9 | | $5.3 | | $29.0 | | $0.9 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2009 and 2008 are as follows:
| | | 2009 | | 2008 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $3.3 | | $6.5 |
| 1 year - 5 years | | 46.1 | | 36.5 |
| 5 years - 10 years | | 53.9 | | 75.7 |
| 10 years - 15 years | | 52.0 | | 36.0 |
| 15 years - 20 years | | 3.5 | | 8.7 |
| 20 years+ | | 8.5 | | 7.5 |
| Total | | $167.3 | | $170.9 |
During the years ended December 31, 2009, 2008, and 2007, proceeds from the dispositions of securities amounted to $95.2 million, $65.1 million, and $64.6 million, respectively. During the years ended December 31, 2009, 2008, and 2007, gross gains of $2.4 million, $1.0 million, and $0.1 million, respectively, and gross losses of $0.6 million, $0.6 million, and $0.2 million, respectively, were recorded in earnings.
Entergy Louisiana
Entergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2009 and 2008 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2009 | | | | | | |
| Equity Securities | | $117.9 | | $15.3 | | $5.3 |
| Debt Securities | | 91.2 | | 3.9 | | 0.9 |
| Total | | $209.1 | | $19.2 | | $6.2 |
| | | | | | | |
| 2008 | | | | | | |
| Equity Securities | | $93.3 | | $3.9 | | $17.2 |
| Debt Securities | | 87.6 | | 7.1 | | 1.6 |
| Total | | $180.9 | | $11.0 | | $18.8 |
The amortized cost of debt securities was $88.2 million as of December 31, 2009 and $82.1 million as of December 31, 2008. As of December 31, 2009, the debt securities have an average coupon rate of approximately 3.95%, an average duration of approximately 4.82 years, and an average maturity of approximately 9.8 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2009:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $- | | $- | | $29.7 | | $0.8 |
| More than 12 months | | 37.5 | | 5.3 | | 0.9 | | 0.1 |
| Total | | $37.5 | | $5.3 | | $30.6 | | $0.9 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2009 and 2008 are as follows:
| | | 2009 | | 2008 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $2.2 | | $1.2 |
| 1 year - 5 years | | 31.9 | | 33.4 |
| 5 years - 10 years | | 23.7 | | 21.4 |
| 10 years - 15 years | | 12.1 | | 10.5 |
| 15 years - 20 years | | 5.5 | | 6.8 |
| 20 years+ | | 15.8 | | 14.3 |
| Total | | $91.2 | | $87.6 |
During the years ended December 31, 2009, 2008, and 2007, proceeds from the dispositions of securities amounted to $47.5 million, $23.5 million, and $23.8 million, respectively. During the years ended December 31, 2009, 2008, and 2007, gross gains of $1.7 million, $0.5 million, and $0.6 million, respectively, and gross losses of $1.1 million, $0.4 million, and $0.3, respectively, were recorded in earnings.
System Energy
System Energy holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 2009 and 2008 are summarized as follows:
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2009 | | | | | | |
| Equity Securities | | $182.3 | | $17.8 | | $14.7 |
| Debt Securities | | 144.7 | | 2.8 | | 0.8 |
| Total | | $327.0 | | $20.6 | | $15.5 |
| | | | | | | |
| 2008 | | | | | | |
| Equity Securities | | $127.8 | | $2.0 | | $36.3 |
| Debt Securities | | 141.0 | | 6.9 | | 3.9 |
| Total | | $268.8 | | $8.9 | | $40.2 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The amortized cost of debt securities was $142.8 million as of December 31, 2009 and $138.0 million as of December 31, 2008. As of December 31, 2009, the debt securities have an average coupon rate of approximately 4.31%, an average duration of approximately 4.67 years, and an average maturity of approximately 7.4 years. The equity securities are generally held in funds that are designed to approximate the return of the Standard & Poor's 500 Index. A relatively small percentage of the securities are held in funds intended to replicate the return of the Wilshire 4500 Index.
The fair value and gross unrealized losses of available-for-sale equity and debt securities, summarized by investment type and length of time that the securities have been in a continuous loss position, are as follows as of December 31, 2009:
| | | Equity Securities | | Debt Securities |
| | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | | (In Millions) |
| | | | | | | | | |
| Less than 12 months | | $- | | $- | | $56.4 | | $0.6 |
| More than 12 months | | 89.3 | | 14.7 | | 3.2 | | 0.2 |
| Total | | $89.3 | | $14.7 | | $59.6 | | $0.8 |
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2009 and 2008 are as follows:
| | | 2009 | | 2008 |
| | | (In Millions) |
| | | | | |
| less than 1 year | | $1.0 | | $2.0 |
| 1 year - 5 years | | 84.0 | | 48.0 |
| 5 years - 10 years | | 36.2 | | 44.0 |
| 10 years - 15 years | | 4.2 | | 10.0 |
| 15 years - 20 years | | 2.3 | | 1.2 |
| 20 years+ | | 17.0 | | 35.8 |
| Total | | $144.7 | | $141.0 |
During the years ended December 31, 2009, 2008, and 2007, proceeds from the dispositions of securities amounted to $393.0 million, $483.4 million, and $105.7 million, respectively. During the years ended December 31, 2009, 2008, and 2007, gross gains of $4.4 million, $4.7 million, and $0.9 million, respectively, and gross losses of $6.5 million, $4.2 million, and $0.4 million, respectively, were recorded in earnings.
Other-than-temporary impairments and unrealized gains and losses
Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy evaluate unrealized losses at the end of each period to determine whether an other-than-temporary impairment has occurred. Effective January 1, 2009, Entergy adopted an accounting pronouncement providing guidance regarding recognition and presentation of other-than-temporary impairments related to investments in debt securities. The assessment of whether an investment in a debt security has suffered an other-than-temporary impairment is based on whether Entergy has the intent to sell or more likely than not will be required to sell the debt security before recovery of its amortized costs. Further, if Entergy does not expect to recover the entire amortized cost basis of the debt security, an other-than-temporary impairment is considered to have occurred and it is measured by the present value of cash flows expected to be collected less the amortized cost basis (credit loss). For debt securities held as of January 1, 2009 for which an other-than-temporary impairment had
Entergy Corporation and Subsidiaries
Notes to Financial Statements
previously been recognized but for which assessment under the new guidance indicates this impairment is temporary, Entergy recorded an adjustment to its opening balance of retained earnings of $11.3 million ($6.4 million net-of-tax). Entergy did not
have anyrecord material
other-than-temporary impairments relating to credit losses on debt securities in 2009. The assessment of whether an investment in an equity security has suffered an other-than-temporary impairment continues to be based on a number of factors including, first, whether Entergy has the ability and intent to hold the investment to recover its value, the duration and severity of any losses, and, then, whether it is expected that the investment will recover its value within a reasonable period of time. Entergy's trusts are managed by third parties who operate in accordance with agreements that define investment guidelines and place restrictions on the purchases and sales of investments. Non-Utility Nuclear recorded charges to other income
of $86 million in
2009, $50 million in 2008,2012, 2011, and
$5 million in 2007,2010, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.
NOTE 18. ENTERGY NEW ORLEANS BANKRUPTCY PROCEEDINGVARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
AsUnder applicable authoritative accounting guidance, a resultvariable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the effectsfollowing characteristics: an insufficient amount of Hurricane Katrina andequity at risk to finance its activities, equity owners who do not have the effect of extensive flooding that resulted from levee breaks in and aroundpower to direct the New Orleans area, on September 23, 2005, Entergy New Orleans filed a voluntary petition in bankruptcy court seeking reorganization relief under Chapter 11significant activities of the U.S. Bankruptcy Code. On May 7, 2007,entity (or have voting rights that are disproportionate to their ownership interest), or where equity holders do not receive expected losses or returns. An entity may have an interest in a VIE through ownership or other contractual rights or obligations, and is required to consolidate a VIE if it is the bankruptcy judge entered an order confirming Entergy New Orleans' planVIE’s primary beneficiary. The primary beneficiary of reorganization. Witha VIE is the receiptentity that has the power to direct the activities of CDBG funds,the VIE that most significantly affect the VIE’s economic performance, and has the agreement on insurance recovery with one of its excess insurers, Entergy New Orleans waivedobligation to absorb losses or has the conditions precedent in its plan of reorganization andright to residual returns that would potentially be significant to the plan became effective on May 8, 2007. Following are significant terms in Entergy New Orleans' plan of reorganization:entity.
· | Entergy New Orleans paid in full, in cash, the allowed third-party prepetition accounts payable (approximately $29 million, including interest). Entergy New Orleans paid interest from September 23, 2005 at the Louisiana judicial rate of interest for 2005 (6%) and 2006 (8%), and at the Louisiana judicial rate of interest (9.5%) plus 1% for 2007 through the date of payment. |
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy consolidate the respective companies from which they lease nuclear fuel, usually in a sale and leaseback transaction. This is because Entergy directs the nuclear fuel companies with respect to nuclear fuel purchases, assists the nuclear fuel companies in obtaining financing, and, if financing cannot be arranged, the lessee (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, or System Energy) is responsible to repurchase nuclear fuel to allow the nuclear fuel company (the VIE) to meet its obligations. During the term of the arrangements, none of the Entergy operating companies have been required to provide financial support apart from their scheduled lease payments. See Note 4 to the financial statements for details of the nuclear fuel companies’ credit facility and commercial paper borrowings and long-term debt that are reported by Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy. These amounts also represent Entergy’s and the respective Registrant Subsidiary’s maximum exposure to losses associated with their respective interests in the nuclear fuel companies.· | Entergy New Orleans issued notes due in three years in satisfaction of its affiliate prepetition accounts payable (approximately $74 million, including interest), including its indebtedness to the Entergy System money pool. Entergy New Orleans included in the principal amount of the notes accrued interest from September 23, 2005 at the Louisiana judicial rate of interest for 2005 (6%) and 2006 (8%), and at the Louisiana judicial rate of interest plus 1% for 2007 through the date of issuance of the notes. Entergy New Orleans will pay interest on the notes from their date of issuance at the Louisiana judicial rate of interest plus 1%. The Louisiana judicial rate of interest is 9.5% for 2007, 8.5% for 2008, 5.5% for 2009, and 3.5% for 2010. |
· | Entergy New Orleans repaid in full, in cash, the outstanding borrowings under the debtor-in-possession credit agreement between Entergy New Orleans and Entergy Corporation (approximately $67 million). |
· | Entergy New Orleans' first mortgage bonds remain outstanding with their stated maturity dates and interest terms. Pursuant to an agreement with its first mortgage bondholders, Entergy New Orleans paid the first mortgage bondholders an amount equal to the one year of interest from the bankruptcy petition date that the bondholders had waived previously in the bankruptcy proceeding (approximately $12 million). |
· | Entergy New Orleans' preferred stock will remain outstanding on its stated dividend terms, and Entergy New Orleans paid its unpaid preferred dividends in arrears (approximately $1 million). |
· | Litigation claims were generally unaltered, and will generally proceed as if Entergy New Orleans had not filed for bankruptcy protection, with exceptions for certain claims. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
(Entergy Corporation)Gulf States Reconstruction Funding I, LLC, and Entergy Texas Restoration Funding, LLC, companies wholly-owned and consolidated by Entergy Texas, are variable interest entities and Entergy Texas is the primary beneficiary. In June 2007, Entergy Gulf States Reconstruction Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Rita reconstruction costs. In November 2009, Entergy Texas Restoration Funding issued senior secured transition bonds (securitization bonds) to finance Entergy Texas’s Hurricane Ike and Hurricane Gustav restoration costs. With the proceeds, the variable interest entities purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. The transition property is reflected as a regulatory asset on the consolidated Entergy Texas balance sheet. The creditors of Entergy Texas do not have recourse to the assets or revenues of the variable interest entities, including the transition property, and the creditors of the variable interest entities do not have recourse to the assets or revenues of Entergy Texas. Entergy Texas has no payment obligations to the variable interest entities except to remit transition charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, is a variable interest entity and Entergy Arkansas is the primary beneficiary. In August 2010, Entergy Arkansas Restoration Funding issued storm cost recovery bonds to finance Entergy Arkansas’s January 2009 ice storm damage restoration costs. With the proceeds, Entergy Arkansas Restoration Funding purchased from Entergy Arkansas the storm recovery property, which is the right to recover from customers through a storm recovery charge amounts sufficient to service the securitization bonds. The storm recovery property is reflected as a regulatory asset on the consolidated Entergy Arkansas balance sheet. The creditors of Entergy Arkansas do not have recourse to the assets or revenues of Entergy Arkansas Restoration Funding, including the storm recovery property, and the creditors of Entergy Arkansas Restoration Funding do not have recourse to the assets or revenues of Entergy Arkansas. Entergy Arkansas has no payment obligations to Entergy Arkansas Restoration Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the storm cost recovery bonds.
Entergy Louisiana Investment Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy Louisiana, is a variable interest entity and Entergy Louisiana is the primary beneficiary. In September 2011, Entergy Louisiana Investment Recovery Funding issued investment recovery bonds to recover Entergy Louisiana’s investment recovery costs associated with the cancelled Little Gypsy repowering project. With the proceeds, Entergy Louisiana Investment Recovery Funding purchased from Entergy Louisiana the investment recovery property, which is the right to recover from customers through an investment recovery charge amounts sufficient to service the bonds. The investment recovery property is reflected as a regulatory asset on the consolidated Entergy Louisiana balance sheet. The creditors of Entergy Louisiana do not have recourse to the assets or revenues of Entergy Louisiana Investment Recovery Funding, including the investment recovery property, and the creditors of Entergy Louisiana Investment Recovery Funding do not have recourse to the assets or revenues of Entergy Louisiana. Entergy Louisiana has no payment obligations to Entergy Louisiana Investment Recovery Funding except to remit investment recovery charge collections. See Note 5 to the financial statements for additional details regarding the investment recovery bonds.
With confirmationEntergy Louisiana and System Energy are also considered to each hold a variable interest in the lessors from which they lease undivided interests in the Waterford 3 and Grand Gulf nuclear plants, respectively. Entergy Louisiana and System Energy are the lessees under these arrangements, which are described in more detail in Note 10 to the financial statements. Entergy Louisiana made payments on its lease, including interest, of $39.1 million in 2012, $50.4 million in 2011, and $35.1 million in 2010. System Energy made payments on its lease, including interest, of $50 million in 2012, $49.4 million in 2011, and $48.6 million in 2010. The lessors are banks acting in the capacity of owner trustee for the benefit of equity investors in the transactions pursuant to trust agreements entered solely for the purpose of facilitating the lease transactions. It is possible that Entergy Louisiana and System Energy may be considered as the primary beneficiary of the planlessors, but Entergy is unable to apply the authoritative accounting guidance with respect to these VIEs because the lessors are not required to, and could not, provide the necessary financial information to consolidate the lessors. Because Entergy accounts for these leasing arrangements as capital financings, however, Entergy believes that consolidating the lessors would not materially affect the financial statements. In the unlikely event of reorganization, Entergy reconsolidated Entergy New Orleansdefault under a lease, remedies available to the lessor include payment by the lessee of the fair value of the undivided interest in the second quarter 2007, retroactive to January 1, 2007. Because Entergy owns allplant, payment of the common stockpresent value of the basic rent payments, or payment of a predetermined casualty value. Entergy New Orleans, reconsolidationbelieves, however, that the obligations recorded on the balance sheets materially represent each company’s potential exposure to loss.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy has also reviewed various lease arrangements, power purchase agreements, and other agreements in which it holds a variable interest. In these cases, Entergy has determined that it is not the primary beneficiary of the related VIE because it does not have the power to direct the activities of the VIE that most significantly affect the amount of net incomeVIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that Entergy records from Entergy New Orleans' operations for any currentwould potentially be significant to the entity, or prior periods, but does result in Entergy New Orleans' results being included in each individual income statement line item in 2007.both.
NOTE 19. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Each Registrant Subsidiary purchases electricity from or sells electricity to the other Registrant Subsidiaries, or both, under rate schedules filed with FERC. The Registrant Subsidiaries purchase fuel from System Fuels; receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations.Operations; and until the first quarter 2011 purchased fuel from System Fuels. These transactions are on an "at cost"“at cost” basis. In addition, Entergy Power sells electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans. RS Cogen sells electricity to Entergy Gulf States Louisiana.
As described in Note 1 to the financial statements, all of System Energy'sEnergy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
Additionally, asAs described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy'sEntergy’s money pool and earn interest income from the money pool. Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans also receivereceived interest income from System Fuels Inc.until the first quarter 2011, when System Fuels repaid each company’s investment in System Fuels. As described in Note 2 to the financial statements, Entergy Gulf States Louisiana and Entergy Louisiana receive preferred membership distributions from Entergy Holdings Company.
The tables below contain the various affiliate transactions of the Utility operating companies, System Energy, and other Entergy affiliates.
Intercompany Revenues
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2009 | | $354.5 | | $475.5 | | $260.2 | | $53.4 | | $87.6 | | $295.0 | | $554.0 |
| 2008 | | $419.1 | | $644.1 | | $257.8 | | $99.7 | | $161.0 | | $438.7 | | $529.0 |
| 2007 | | $302.7 | | $234.3 | | $317.4 | | $145.9 | | $102.9 | | $398.8 | | $553.2 |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2012 | | $324.0 | | $380.6 | | $138.2 | | $36.1 | | $43.9 | | $313.2 | | $622.1 |
| 2011 | | $293.8 | | $574.5 | | $139.0 | | $125.1 | | $96.9 | | $264.1 | | $563.4 |
| 2010 | | $307.1 | | $462.9 | | $228.0 | | $59.4 | | $56.0 | | $372.8 | | $558.6 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Intercompany Operating Expenses
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| | | (1) | | (2) | | (3) | | | | (4) | | | | |
| 2009 | | $844.5 | | $547.6 | | $496.6 | | $353.1 | | $212.6 | | $417.6 | | $136.3 |
| 2008 | | $723.4 | | $908.8 | | $587.5 | | $385.1 | | $213.1 | | $553.7 | | $118.5 |
| 2007 | | $766.0 | | $619.2 | | $521.9 | | $369.1 | | $222.2 | | $483.0 | | $115.2 |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| | | (1) | | (2) | | (3) | | | | (4) | | | | |
| 2012 | | $580.7 | | $532.3 | | $597.4 | | $352.7 | | $247.2 | | $386.1 | | $147.4 |
| 2011 | | $752.7 | | $563.1 | | $574.0 | | $337.2 | | $226.6 | | $486.6 | | $131.5 |
| 2010 | | $545.6 | | $602.7 | | $483.0 | | $372.9 | | $235.8 | | $519.0 | | $122.7 |
| (1) | Includes $1.4 million in 2012, $1.2 million in 2011, and $0.1 million in 2009, $0.5 million in 2008, and $4.8 million in 20072010 for power purchased from Entergy Power. |
| (2) | Includes power purchased from RS Cogen of $49.3$2.8 million in 2009, $82.52012, $41.1 million in 2008, $68.42011, and $50.8 million in 2007.2010. |
| (3) | Includes power purchased from Entergy Power of $11.6$14.3 million in 2009 and $10.52012, $14.5 million in 2008.2011, and $12.0 million in 2010. |
| (4) | Includes power purchased from Entergy Power of $11.3$14.1 million in 2009 and $10.32012, $14.2 million in 2008.2011, and $11.8 million in 2010. |
Intercompany Interest and Investment Income
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2009 | | $0.9 | | $19.5 | | $55.5 | | $0.8 | | $0.7 | | $0.4 | | $1.9 |
| 2008 | | $1.4 | | $12.3 | | $31.4 | | $0.9 | | $2.0 | | $2.6 | | $2.1 |
| 2007 | | $2.8 | | $7.9 | | $1.7 | | $2.4 | | $0.4 | | $4.1 | | $6.1 |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) |
| | | | | | | | | | | | | | | |
| 2012 | | $0.0 | | $28.2 | | $78.2 | | $0.0 | | $0.0 | | $0.1 | | $0.0 |
| 2011 | | $0.1 | | $32.5 | | $78.1 | | $0.1 | | $0.1 | | $0.0 | | $0.6 |
| 2010 | | $0.6 | | $26.5 | | $67.6 | | $0.3 | | $0.2 | | $0.1 | | $0.7 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 20. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 20092012 and 20082011 for Entergy Corporation and subsidiaries were:
| | Operating Revenues | | Operating Income | | Net Income |
| | (In Thousands) |
| 2009: | |
First Quarter | $2,789,112 | | $506,527 | | $235,335 |
Second Quarter | $2,520,789 | | $474,496 | | $226,813 |
Third Quarter | $2,937,095 | | $800,304 | | $455,169 |
Fourth Quarter | $2,498,654 | | $503,119 | | $313,775 |
| | | | | | |
| 2008: | | | | | |
First Quarter | $2,864,734 | | $606,233 | | $308,749 |
Second Quarter | $3,264,271 | | $568,109 | | $270,954 |
Third Quarter | $3,963,884 | | $752,092 | | $470,289 |
Fourth Quarter | $3,000,867 | | $356,733 | | $170,574 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements| | Operating Revenues | | Operating Income (Loss) | | Consolidated Net Income
(Loss) | | Net Income
(Loss) Attributable to Entergy Corporation |
| | (In Thousands) |
| 2012: | | | |
First Quarter | $2,383,659 | | ($56,857) | | ($146,740) | | ($151,683) |
Second Quarter | $2,518,600 | | $342,984 | | $370,583 | | $365,001 |
Third Quarter | $2,963,560 | | $690,852 | | $342,670 | | $337,088 |
Fourth Quarter | $2,436,260 | | $324,202 | | $301,850 | | $296,267 |
| | | | |
| 2011: | | | |
First Quarter | $2,541,208 | | $510,891 | | $253,678 | | $248,663 |
Second Quarter | $2,803,279 | | $558,738 | | $320,598 | | $315,583 |
Third Quarter | $3,395,553 | | $600,909 | | $633,069 | | $628,054 |
Fourth Quarter | $2,489,033 | | $342,696 | | $160,027 | | $154,139 |
Earnings per Average Common Share
| | 2009 | | 2008 | 2012 | | 2011 |
| | Basic | | Diluted | | Basic | | Diluted | Basic | | Diluted | | Basic | | Diluted |
| | | | | | | | | | | | | | | |
| First Quarter | $1.22 | | $1.20 | | $1.60 | | $1.56 | ($0.86) | | ($0.86) | | $1.39 | | $1.38 |
| Second Quarter | $1.16 | | $1.14 | | $1.42 | | $1.37 | $2.06 | | $2.06 | | $1.77 | | $1.76 |
| Third Quarter | $2.35 | | $2.32 | | $2.47 | | $2.41 | $1.90 | | $1.89 | | $3.55 | | $3.53 |
| Fourth Quarter | $1.66 | | $1.64 | | $0.90 | | $0.89 | $1.67 | | $1.67 | | $0.88 | | $0.88 |
As discussed in more detail in Note 1 to the financial statements, results of operations for 2012 include a $355.5 million ($223.5 million after-tax) impairment charge to write down the carrying values of Vermont Yankee and related assets to their fair values.
The business of the Utility operating companies is subject to seasonal fluctuations with the peak periods occurring during the third quarter. Operating results for the Registrant Subsidiaries for the four quarters of 20092012 and 20082011 were:
| Operating Revenue |
| | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2009: | | | | | | | | | | | | | | |
First Quarter | | $535,994 | | $488,905 | | $529,257 | | $261,705 | | $171,094 | | $413,474 | | $127,372 |
Second Quarter | | $518,009 | | $441,263 | | $527,156 | | $290,615 | | $137,137 | | $377,319 | | $130,387 |
Third Quarter | | $649,395 | | $486,772 | | $624,829 | | $356,545 | | $174,071 | | $399,496 | | $148,789 |
Fourth Quarter | | $507,865 | | $427,446 | | $502,344 | | $268,439 | | $158,120 | | $373,534 | | $147,459 |
| 2008: | | | | | | | | | | | | | | |
First Quarter | | $499,374 | | $558,564 | | $564,744 | | $294,850 | | $191,355 | | $397,042 | | $114,372 |
Second Quarter | | $580,462 | | $702,536 | | $753,778 | | $351,982 | | $227,508 | | $565,349 | | $128,366 |
Third Quarter | | $711,835 | | $856,882 | | $1,021,588 | | $491,113 | | $215,603 | | $621,321 | | $142,045 |
Fourth Quarter | | $536,678 | | $615,383 | | $711,184 | | $324,237 | | $179,917 | | $428,546 | | $144,215 |
| Operating Income (Loss) |
| | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2009: | | | | | | | | | | | | | | |
First Quarter | | $50,055 | | $56,825 | | $41,377 | | $18,649 | | $10,858 | | $20,452 | | $43,481 |
Second Quarter | | $57,346 | | $58,437 | | $55,011 | | $51,309 | | $18,579 | | $16,434 | | $46,122 |
Third Quarter | | $110,666 | | $84,018 | | $125,919 | | $67,333 | | $22,302 | | $74,327 | | $43,461 |
Fourth Quarter | | ($1,226) | | $91,155 | | $42,113 | | $28,896 | | $8,999 | | $39,879 | | $40,945 |
| 2008: | | | | | | | | | | | | | | |
First Quarter | | $52,661 | | $58,867 | | $47,219 | | $19,169 | | $19,368 | | $27,134 | | $45,342 |
Second Quarter | | $65,801 | | $50,740 | | $73,127 | | $40,107 | | $20,905 | | $42,238 | | $44,562 |
Third Quarter | | $108,293 | | $97,111 | | $97,600 | | $55,127 | | $21,985 | | $48,763 | | $50,936 |
Fourth Quarter | | ($21,261) | | $37,000 | | $32,152 | | $20,787 | | $7,501 | | $17,784 | | $48,393 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Operating Revenues
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2012: | | | | | | | | | | | | | | |
First Quarter | | $475,178 | | $399,622 | | $482,358 | | $261,760 | | $129,156 | | $326,924 | | $126,034 |
Second Quarter | | $502,022 | | $401,356 | | $561,787 | | $277,204 | | $129,244 | | $358,067 | | $113,699 |
Third Quarter | | $656,201 | | $434,451 | | $614,044 | | $321,771 | | $161,565 | | $489,078 | | $188,680 |
Fourth Quarter | | $493,603 | | $419,465 | | $491,254 | | $259,631 | | $149,775 | | $407,427 | | $193,705 |
| 2011: | | | | | | | | | | | | | | |
First Quarter | | $443,498 | | $495,898 | | $515,434 | | $288,983 | | $158,256 | | $348,884 | | $128,395 |
Second Quarter | | $516,833 | | $522,562 | | $651,847 | | $302,194 | | $150,498 | | $444,423 | | $129,120 |
Third Quarter | | $658,356 | | $596,948 | | $786,814 | | $365,569 | | $182,032 | | $556,955 | | $152,431 |
Fourth Quarter | | $465,623 | | $519,001 | | $554,820 | | $309,724 | | $139,399 | | $406,937 | | $153,465 |
Operating Income (Loss)
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2012: | | | | | | | | | | | | | | |
First Quarter | | $39,816 | | $55,226 | | $36,142 | | $28,338 | | $3,250 | | $25,063 | | $35,456 |
Second Quarter | | $87,899 | | $56,037 | | ($41,253) | | $42,225 | | $10,009 | | $48,983 | | $38,245 |
Third Quarter | | $152,836 | | $85,561 | | $121,725 | | $59,331 | | $19,565 | | $61,234 | | $58,934 |
Fourth Quarter | | $26,833 | | $52,138 | | $32,397 | | $30,621 | | $3,066 | | $34,533 | | $58,776 |
| 2011: | | | | | | | | | | | | | | |
First Quarter | | $60,905 | | $83,069 | | $47,561 | | $37,286 | | $16,933 | | $45,593 | | $36,387 |
Second Quarter | | $99,072 | | $89,860 | | $96,648 | | $50,280 | | $15,710 | | $57,682 | | $33,996 |
Third Quarter | | $164,822 | | $100,276 | | ($61,706) | | $60,935 | | $36,603 | | $86,810 | | $38,520 |
Fourth Quarter | | $33,555 | | $57,506 | | $3,606 | | $32,888 | | ($6,118) | | $24,935 | | $41,699 |
Net Income (Loss)
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2012: | | | | | | | | | | | | | | |
First Quarter | | $13,874 | | $28,358 | | $33,295 | | $8,682 | | $40 | | $1,745 | | $26,536 |
Second Quarter | | $45,755 | | $50,389 | | $130,714 | | $15,914 | | $7,186 | | $16,204 | | $35,368 |
Third Quarter | | $82,551 | | $50,210 | | $80,208 | | $27,080 | | $10,555 | | $19,234 | | $30,616 |
Fourth Quarter | | $10,185 | | $30,020 | | $36,864 | | ($4,908) | | ($716) | | $4,788 | | $19,346 |
| 2011: | | | | | | | | | | | | | | |
First Quarter | | $25,608 | | $46,619 | | $40,298 | | $17,314 | | $8,927 | | $15,726 | | $19,336 |
Second Quarter | | $50,298 | | $50,405 | | $75,103 | | $23,829 | | $8,207 | | $23,097 | | $21,986 |
Third Quarter | | $80,945 | | $53,170 | | $337,722 | | $33,169 | | $18,943 | | $40,875 | | $14,263 |
Fourth Quarter | | $8,040 | | $51,410 | | $20,800 | | $34,417 | | ($101) | | $1,147 | | $8,612 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| Net Income (Loss) |
| | | | | | | | | | | | | | | |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| 2009: | | | | | | | | | | | | | | |
First Quarter | | $16,070 | | $27,121 | | $36,538 | | $6,238 | | $5,399 | | $6,303 | | $22,392 |
Second Quarter | | $16,423 | | $28,802 | | $39,990 | | $23,927 | | $8,995 | | $5,172 | | $23,693 |
Third Quarter | | $52,939 | | $46,212 | | $86,969 | | $34,558 | | $12,272 | | $38,181 | | $22,026 |
Fourth Quarter | | ($18,557) | | $50,912 | | $69,348 | | $12,913 | | $4,359 | | $14,185 | | ($19,203) |
| 2008: | | | | | | | | | | | | | | |
First Quarter | | $22,718 | | $30,826 | | $19,596 | | $5,679 | | $7,947 | | $7,712 | | $21,601 |
Second Quarter | | $27,521 | | $23,187 | | $36,544 | | $20,130 | | $11,631 | | $21,416 | | $22,091 |
Third Quarter | | $50,273 | | $59,935 | | $64,225 | | $27,924 | | $12,104 | | $22,916 | | $22,384 |
Fourth Quarter | | ($53,360) | | $30,819 | | $37,178 | | $5,977 | | $3,265 | | $5,851 | | $24,991 |
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans |
| | | (In Thousands) |
| 2012: | | | | | | | | | | |
First Quarter | | $12,156 | | $28,152 | | $31,557 | | $7,975 | | ($201) |
Second Quarter | | $44,037 | | $50,183 | | $128,976 | | $15,207 | | $6,945 |
Third Quarter | | $80,833 | | $50,004 | | $78,470 | | $26,373 | | $10,314 |
Fourth Quarter | | $8,466 | | $29,813 | | $35,128 | | ($5,615) | | ($958) |
| 2011: | | | | | | | | | | |
First Quarter | | $23,890 | | $46,413 | | $38,560 | | $16,607 | | $8,686 |
Second Quarter | | $48,580 | | $50,199 | | $73,365 | | $23,122 | | $7,966 |
Third Quarter | | $79,227 | | $52,964 | | $335,984 | | $32,462 | | $18,702 |
Fourth Quarter | | $6,321 | | $51,203 | | $19,064 | | $33,710 | | ($343) |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy is an integrated energy company engaged primarily in electric power production and retail electric distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of aggregate electric generating capacity, including over 10,000 MW of nuclear-fueled capacity. Entergy’s Utility business delivers electricity to 2.8 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy generated annual revenues of $10.3 billion in 2012 and had approximately 15,000 employees as of December 31, 2012.
Entergy operates primarily through two business segments: Utility and Entergy Wholesale Commodities.
| · | The Utility business segment includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Mississippi, Texas, and Louisiana, including the City of New Orleans; and operates a small natural gas distribution business. As discussed in more detail in “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis in December 2011, Entergy entered into an agreement to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp. |
| · | The Entergy Wholesale Commodities business segment includes the ownership and operation of six nuclear power plants located in the northern United States and the sale of the electric power produced by those plants to wholesale customers. This business also provides services to other nuclear power plant owners. Entergy Wholesale Commodities also owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. |
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy aspires to achieve industry-leading total shareholder returns in an environmentally responsible fashion by leveraging the scale and expertise inherent in its core nuclear and utility operations. Entergy’s current scope includes electricity generation, transmission and distribution as well as natural gas distribution. Entergy focuses on operational excellence with an emphasis on safety, reliability, customer service, sustainability, cost efficiency, and risk management. Entergy also focuses on portfolio management to make periodic buy, build, hold, or sell decisions based upon its analytically-derived points of view, which are updated as market conditions evolve.
The Utility business segment includes six wholly-owned retail electric utility subsidiaries: Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. These companies generate, transmit, distribute and sell electric power to retail and wholesale customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy Gulf States Louisiana and Entergy New Orleans also provide natural gas utility services to customers in and around Baton Rouge, Louisiana, and New Orleans, Louisiana, respectively. Also included in the Utility is System Energy, a wholly-owned subsidiary of Entergy Corporation that owns or leases 90 percent of Grand Gulf. System Energy sells its power and capacity from Grand Gulf at wholesale to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
The six retail utility subsidiaries are each regulated by the FERC and by state utility commissions, or, in the case of Entergy New Orleans, the City Council. System Energy is regulated by the FERC asbecause all of its transactions are at the wholesale level. The Utility continues to operate as a rate-regulated business as efforts toward deregulation have been delayed, abandoned, or not initiated in its service territories.wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy'sEntergy’s strong support for the environment.
The
Part I Item 1
Entergy Corporation, Utility is focused on providing highly reliableoperating companies, and cost-effective electricity and gas service while working in an environment that provides the highest level of safety for its employees. Since 1998, the Utility has significantly improved key customer service, reliability, and safety metrics and continues to actively pursue additional improvements.System Energy
Customers
As of December 31, 2009,2012, the Utility operating companies provided retail electric and gas service to customers in Arkansas, Louisiana, Mississippi, and Texas, as follows:
| | | | Electric Customers | | Gas Customers | | | | Electric Customers | | Gas Customers |
| | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) | Area Served | | (In Thousands) | | (%) | | (In Thousands) | | (%) |
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | Portions of Arkansas | | 689 | | 25% | | | | | Portions of Arkansas | | 696 | | 25% | | | | |
| Entergy Gulf States Louisiana | Portions of Louisiana | | | | | | | | | Portions of Louisiana | | 387 | | 14% | | 92 | | 47% |
| Entergy Louisiana | Portions of Louisiana | | 663 | | 24% | | | | | Portions of Louisiana | | 673 | | 24% | | | | |
| Entergy Mississippi | Portions of Mississippi | | 435 | | 16% | | | | | Portions of Mississippi | | 440 | | 16% | | | | |
| Entergy New Orleans | City of New Orleans* | | 150 | | 6% | | 96 | | 51% | City of New Orleans* | | 165 | | 6% | | 102 | | 53% |
| Entergy Texas | Portions of Texas | | 403 | | 15% | | | | | Portions of Texas | | 417 | | 15% | | | | |
| Total customers | | | 2,719 | | 100% | | 188 | | 100% | | | 2,778 | | 100% | | 194 | | 100% |
| * | Excludes the Algiers area of the city, where Entergy Louisiana provides electric service. |
Electric Energy Sales
The electric energy sales of the Utility operating companies are subject to seasonal fluctuations, with the peak sales period normally occurring during the third quarter of each year. On June 24, 2009,July 30, 2012, Entergy reached a 20092012 peak demand of 21,009 MW,21,866 MWh, compared to the 20082011 peak of 21,241 MW22,387 MWh recorded on July 28 of that year.August 3, 2011. Selected electric energy sales data is shown in the table below:
Selected 2012 Electric Energy Sales Data
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | | (In GWh) |
Sales to retail customers | | 21,087 | | 19,581 | | 31,710 | | 13,273 | | 5,009 | | 16,344 | | - | | 107,004 |
| Sales for resale: | | | | | | | | | | | | | | | | |
Affiliates | | 7,926 | | 7,727 | | 2,156 | | 232 | | 978 | | 5,702 | | 6,606 | | - |
Others | | 1,093 | | 941 | | 65 | | 265 | | 8 | | 827 | | - | | 3,200 |
Total | | 30,106 | | 28,249 | | 33,931 | | 13,770 | | 5,995 | | 22,873 | | 6,606 | | 110,204 |
| | | | | | | | | | | | | | | | | |
Average use per residential customer (kWh) | | 13,460 | | 15,603 | | 14,903 | | 15,055 | | 12,081 | | 15,353 | | - | | 14,565 |
| (a) | Includes the effect of intercompany eliminations. |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Selected 2009 Electric Energy Sales Data
| | | Entergy Arkansas | | Entergy Gulf States Louisiana | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | | (In GWh) |
Sales to retail customers | | 19,926 | | 17,962 | | 28,396 | | 12,697 | | 4,721 | | 15,446 | | - | | 99,148 |
| Sales for resale: | | | | | | | | | | | | | | | | |
Affiliates | | 9,980 | | 7,084 | | 1,513 | | 198 | | 1,528 | | 3,630 | | 9,898 | | - |
Others | | 1,631 | | 2,546 | | 109 | | 330 | | 15 | | 231 | | - | | 4,862 |
Total | | 31,537 | | 27,592 | | 30,018 | | 13,225 | | 6,264 | | 19,307 | | 9,898 | | 104,010 |
| | | | | | | | | | | | | | | | | |
Average use per residential customer (kWh) | | 12,855 | | 15,697 | | 15,092 | | 14,647 | | 11,891 | | 15,463 | | - | | 14,423 |
(a) | Includes the effect of intercompany eliminations. |
The following table illustrates the Utility operating companies' 2009companies’ 2012 combined electric sales volume as a percentage of total electric sales volume, and 20092012 combined electric revenues as a percentage of total 20092012 electric revenue, each by customer class.
| Customer Class | | % of Sales Volume | | % of Revenue | | % of Sales Volume | | % of Revenue |
| | | | | | | | | |
| Residential | | 32.3 | | 38.1 | | 31.4 | | 38.4 |
| Commercial | | 26.4 | | 27.7 | | 26.1 | | 27.6 |
| Industrial (a) | | 34.3 | | 25.3 | | 37.4 | | 25.9 |
| Governmental | | 2.3 | | 2.6 | | 2.2 | | 2.5 |
| Wholesale | | 4.7 | | 6.3 | |
| Wholesale/Other | | | 2.9 | | 5.6 |
| (a) | Major industrial customers are in the chemical, petroleum refining, and pulp and paper industries. |
See "Selected“Selected Financial Data"Data” for each of the Utility operating companies for the detail of their sales by customer class for 2005-2009.2008-2012.
Selected 20092012 Natural Gas Sales Data
Entergy New Orleans and Entergy Gulf States Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Gulf States Louisiana sold 9,171,2018,924,256 and 6,380,3756,104,341 Mcf, respectively, of natural gas to retail customers in 2009.2012. In 2009, 96%2012, 97% of Entergy Gulf States Louisiana'sLouisiana’s operating revenue was derived from the electric utility business, and only 4%3% from the natural gas distribution business. For Entergy New Orleans, 84%86% of operating revenue was derived from the electric utility business and 16%14% from the natural gas distribution business in 2009.2012. Following is data concerning Entergy New Orleans' 2009Orleans’s 2012 retail operating revenue sources.
Customer Class | | Electric Operating Revenue | | Natural Gas Revenue |
| | | | | |
| Residential | | 38% | | 49% |
| Commercial | | 38% | | 25% |
| Industrial | | 8% | | 10% |
| Governmental/Municipal | | 16% | | 16% |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy Customer Class | | Electric Operating Revenue | | Natural Gas Revenue |
| | | | | |
| Residential | | 40% | | 50% |
| Commercial | | 38% | | 27% |
| Industrial | | 7% | | 7% |
| Governmental/Municipal | | 15% | | 16% |
Retail Rate Regulation
General (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings on a consistent basis.proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies'companies’ retail rate mechanisms are discussed below.
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas'Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the twelve-month period commencing on April 1 of each year to develop an energy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider tariff also allows an interim rate request depending upon the level of over- or under-recovery of fuel and purchased energy costs. In December 2007 the APSC issued an order stating that Entergy Arkansas'Arkansas’s energy cost recovery rider will remain in effect, and any future termination of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing. See Note 2 to the financial statements for a discussion
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas'Arkansas’s storm restoration costs.
Entergy Gulf States Louisiana
Fuel Recovery
Entergy Gulf States Louisiana'sLouisiana’s electric rates include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
To help stabilize electricity costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Entergy Gulf States Louisiana'sLouisiana’s gas rates include a purchased gas adjustment clause based on estimated gas costs for the billing month adjusted by a surcharge or credit that arises from an annual reconciliation of fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
To help stabilize retail gas costs, Entergy Gulf States Louisiana received approval from the LPSC to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy Gulf States Louisiana hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Gulf States Louisiana'sLouisiana’s filings to recover storm-related costs.
Entergy Louisiana
Fuel Recovery
Entergy Louisiana'sLouisiana’s rate schedules include a fuel adjustment clause designed to recover the cost of fuel and purchased power costs. The fuel adjustment clause contains a surcharge or credit for deferred fuel expense and related carrying charges arising from the monthly reconciliation of actual fuel costs incurred with fuel cost revenues billed to customers, including carrying charges.
In the Delaney vs. Entergy Louisiana proceeding, the LPSC ordered Entergy Louisiana, beginning with the May 2000 fuel adjustment clause filing, to re-price costs flowed through its fuel adjustment clause related to the Evangeline gas contract so that the price included for fuel adjustment clause recovery shall thereafter be at the rate of the Henry Hub first of the month cash market price (as reported by the publication Inside FERC) plus $0.24 per mmBtu for the month for which the fuel adjustment clause is calculated, irrespective of the actual cost for the Evangeline contract quantity reflected in that month'smonth’s fuel adjustment clause. The Evangeline gas contract expired on January 1, 2013.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC in 2001 to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Louisiana hedges approximately one-third of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Part I Item 1
Entergy Louisiana settled a proceeding that concerned a contract entered into by Entergy Louisiana to purchase, through 2031, energy generated by a hydroelectric facility known as the Vidalia project. In the settlement, the LPSC approved Entergy Louisiana's proposed treatment of the regulatory effect of the benefit from a tax accounting election related to that project. In general, the settlement permits Entergy Louisiana to keep a portion of the tax benefit in exchange for bearing the risk associated with sustaining the tax treatment. The LPSC settlement divided the term of the Vidalia contract into two segments: 2002-2012Corporation, Utility operating companies, and 2013-2031. During the first eight years of the 2002-2012 segment, Entergy Louisiana agreed to credit rates by flowing through its fuel adjustment calculation $11 million each year, beginning monthly in October 2002. Entergy Louisiana must credit rates in this way and by this amount even if Entergy Louisiana is unable to sustain the tax deduction. Entergy Louisiana also must credit rates by $11 million each year for an additional two years unless either the tax accounting method elected is retroactively repealed or the IRS denies the entire deduction related to the tax accounting method. In addition, in accordance with an LPSC settlement, Entergy Louisiana credited rates in August 2007 by $11.8 million (including interest) as a result of a settlement with the IRS of the 2001 tax treatment of the Vidalia contract. Entergy Louisiana agreed to credit ratepayers additional amounts unless the tax accounting election was not sustained. During the years 2013-2031, Entergy Louisiana and its ratepayers would share the remaining benefits of this tax accounting election. Note 8 to the financial statements contains further discussion of the obligations related to the Vidalia project.System Energy
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy Louisiana'sLouisiana’s filings to recover storm-related costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Mississippi
Fuel Recovery
Entergy Mississippi'sMississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased energy costs. The rider utilizespreviously utilized projected energy costs filed quarterly by Entergy Mississippi to develop an energy cost rate. Beginning January 2013, Entergy Mississippi will make those filings annually. The energy cost rate is redeterminedfor each calendar quarteryear will be redetermined annually and includeswill include a true-up adjustment reflecting the over-recovery or under-recovery of the energy costcosts as of the second quarter preceding12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the redetermination.authority of the MPSC.
Power Management Rider
The MPSC approved the purchase of the Attala power plant in November 2005. In December 2005 the MPSC issued an order approving the investment cost recovery through itsEntergy Mississippi’s power management rider. Entergy Mississippi is allowed to recover the annual ownership costs of the Attala plant through the power management rider and limiteduntil it files a general rate case. The MPSC approved the recovery to a period that begins with the closing datepurchase of the purchaseHinds power plant in February 2012. In August and ends the earlier of the date costs are incorporated into base rates or December 31, 2006. As a consequence of the events surrounding Entergy Mississippi's ongoing efforts to recover storm restoration costs associated with Hurricane Katrina, in October 2006,2012, the MPSC approved a revision toissued orders approving the investment cost recovery through Entergy Mississippi'sMississippi’s power management rider. The revision hasorders have the effect of allowing Entergy Mississippi to recover the annual ownership costs of the AttalaHinds plant until such time asit files a general rate case is filed.case. Entergy Mississippi acquired the Hinds plant on November 30, 2012. Recovery of the Hinds plant costs through the power management rider commenced with January 2013 bills.
To help stabilize electricity costs, Entergy Mississippi received approval from the MPSC to hedge its exposure to natural gas price volatility through the use of financial instruments. Entergy Mississippi hedges approximately one-half of the projected exposure to natural gas price changes for the gas used to serve its native electric load for all months of the year. The hedge quantity is reviewed on an annual basis.
Storm Cost Recovery
See Note 2Entergy Mississippi maintains a storm damage reserve pursuant to orders of the MPSC and consistent with regulatory accounting requirements. Entergy Mississippi's storm damage provision is funded through its storm damage rider schedule. In August 2011, Entergy Mississippi filed with the MPSC a notice of its intent to revise the storm damage rider schedule to recover over a 36-month period approximately $30 million and to increase the level of monthly accruals to the financial statementsstorm damage provision from $750,000 per month to $1.75 million per month, and to increase the level of the storm reserve cap during which funds will accrue from $15 million to $25 million. The cap is the level of the storm damage provision balance at which monthly accruals would temporarily cease. In two orders issued in July 2012, the MPSC temporarily increased Entergy Mississippi’s storm damage provision monthly accrual from $0.75 million to $2.0 million for a discussionbills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills. Beginning with January 2013 bills, the monthly accrual to the storm damage provision reverted back to $750,000. The MPSC has also ordered that Entergy Mississippi's filings to recover storm-related costs.Mississippi will annually submit its storm costs for audit.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy New Orleans
Fuel Recovery
Entergy New Orleans'Orleans’s electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased power costs incurred with fuel cost revenues billed to customers, including carrying charges. In June 2006, the City Council authorized the recovery of all Grand Gulf costs through Entergy New Orleans' fuel adjustment clause (a significant portion of Grand Gulf costs was previously recovered through base rates), and continued that authorization in approving the October 2006 formula rate plan filing settlement. Effective June 2009, the majority of Grand Gulf costs were realigned to base rates and are no longer flowed through the fuel adjustment clause.
Entergy New Orleans'Orleans’s gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005 the City Council approved modification of the current gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.
To help stabilize retail gas costs, Entergy New Orleans received approval from the City Council to hedge its exposure to natural gas price volatility for its gas purchased for resale through the use of financial instruments. Entergy New Orleans hedges approximately one-half of the projected natural gas volumes used to serve its natural gas customers for November through March. The hedge quantity is reviewed on an annual basis.
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Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans'Orleans’s efforts to recover storm-related costs.
Entergy Texas
Fuel Recovery
Entergy Texas'Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges,interest, that are not recoveredincluded in base rates. The fixed fuel factor formula was revised and approved by a PUCT order in August 2006. The new formula was implemented in September 2006. Under the new method, semi-annualSemi-annual revisions of the fixed fuel factor will continue to beare made in March and September based on the expected change in the market price of natural gas over the next 12 months. The method also accounts forand changes in resource mix and retail sales. To the extent actual costs vary from the fixed fuel factor, refunds or surcharges are required or permitted.mix. The amounts collected under theEntergy Texas’s fixed fuel factor through the start of retail open accessand any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT. The PUCT fuel cost reviews are discussed in Note 2 to the financial statements.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Texas’s storm restoration costs.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that requires Entergy Texas to cease all activities relating to Entergy Texas’s transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining another power region. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the new law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region. In response to the new law, Entergy Texas in June 2009 gave notice to the PUCT of the withdrawal of its previously filed transition to competition plan, and requested that its transition to competition proceeding be dismissed. In July 2009 the ALJ dismissed the proceeding.
The new law also contains provisions that allow Entergy Texas take advantage of a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
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In September 2011, the PUCT adopted a proposed rule implementing a Distribution Cost Recovery Factor to recover capital and capital-related costs related to distribution infrastructure. The Distribution Cost Recovery Factor permits utilities once per year to implement an increase or decrease in rates above or below amounts reflected in base rates to reflect depreciation expense, federal income tax and other taxes, and return on investment. The Distribution Cost Recovery Factor rider may be changed a maximum of four times between base rate cases, and expires in January 2017, unless otherwise extended by the Texas Legislature.
The new law further amends already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the new law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall “purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer”; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The new law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction.
Entergy Texas and the other parties to the PUCT proceeding to determine the design of the competitive generation tariff were involved in negotiations throughout 2011 and 2012 with the objective of resolving as many disputed issues as possible regarding the tariff. After a hearing in April 2012 to address certain issues unresolved among the parties, the PUCT rejected Entergy Texas’s contention that unrecovered costs included the embedded generation costs that Entergy Texas failed to recover when a customer migrated to competitive generation service. The PUCT further determined that unrecovered costs consist only of those costs necessary to implement and administer the competitive generation program and do not include lost revenues or embedded generation costs. The PUCT also ruled that the amount of customer load that may be included in the competitive generation service program is limited to 115 MW. The remaining negotiations resulted in the narrowing of some additional issues but also resulted in filing testimony asking the PUCT to resolve certain remaining issues related to the design of the tariff.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 307 incorporated cities and towns in Arkansas. These franchises are unlimited in duration and continue unless the municipalities purchase the utility property. In Arkansas franchises are considered to be contracts and, therefore, are terminable upon breach ofpursuant to the terms of the franchise.franchise agreement and applicable statutes.
Entergy Gulf States Louisiana holds non-exclusive franchises permits, or certificates of convenience and necessity to provide electric service in approximately 56 incorporated municipalities and the unincorporated areas of approximately 18 parishes, and to provide gas service in the City of Baton Rouge and the unincorporated areas of two parishes. Most of Entergy Gulf States Louisiana'sLouisiana’s franchises have a term of 60 years. Entergy Gulf States Louisiana'sLouisiana’s current electric franchises expire during 2015-2046.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 116 incorporated Louisiana municipalities. Most of these franchises have 25-year terms. Entergy Louisiana also supplies electric service in approximately 353 unincorporated communities, all of which are located in the 45 Louisiana parishes in which it holds non-exclusive franchises. Entergy Louisiana'sLouisiana’s electric franchises expire during 2010-2036.2015-2036.
Entergy Mississippi has received from the MPSC certificates of public convenience and necessity to provide electric service to areas within 45 counties, including a number of municipalities, in western Mississippi. Under Mississippi statutory law, such certificates are exclusive. Entergy Mississippi may continue to serve in such municipalities upon payment of a statutory franchise fee, regardless of whether an original municipal franchise is still in existence.
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Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances (except electric service in Algiers, which is provided by Entergy Louisiana). These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New Orleans'Orleans’s electric and gas utility properties.
Entergy Texas holds a certificate of convenience and necessity from the PUCT to provide electric service to areas within approximately 2627 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas was typically is granted 50-year franchises, but recently has been receiving 25-year franchises. Entergy Texas'Texas’s electric franchises expire during 2010-2045.2013-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
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Property and Other Generation Resources
Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2009,2012, is indicated below:
| | | Owned and Leased Capability MW(1) | | Owned and Leased Capability MW(1) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | 4,799 | | 1,682 | | 1,839 | | 1,208 | | 70 | | 5,274 | | 2,163 | | 1,828 | | 1,209 | | 74 |
| Entergy Gulf States Louisiana | | 3,329 | | 1,988 | | 978 | | 363 | | - | | 3,275 | | 1,941 | | 975 | | 359 | | - |
| Entergy Louisiana | | 5,834 | | 4,658 | | 1,176 | | - | | - | | 5,413 | | 4,254 | | 1,159 | | - | | - |
| Entergy Mississippi | | 3,223 | | 2,803 | | - | | 420 | | - | | 3,502 | | 3,082 | | - | | 420 | | - |
| Entergy New Orleans | | 745 | | 745 | | - | | - | | - | | 705 | | 705 | | - | | - | | - |
| Entergy Texas | | 2,543 | | 2,274 | | - | | 269 | | - | | 2,535 | | 2,269 | | - | | 266 | | - |
| System Energy | | 1,133 | | - | | 1,133 | | - | | - | | 1,287 | | - | | 1,287 (2) | | - | | - |
| Total | | 21,606 | | 14,150 | | 5,126 | | 2,260 | | 70 | | 21,991 | | 14,414 | | 5,249 | | 2,254 | | 74 |
| (1) | "“Owned and Leased Capability"Capability” is the dependable load carrying capability as demonstrated under actual operating conditions based on the primary fuel (assuming no curtailments) that each station was designed to utilize. |
| (2) | Includes estimate, pending further testing, of the rerate for recovered performance (approximately 55 MW) and uprate (approximately 178 MW) completed in 2012. |
The Entergy System's load and capacity projections are reviewed periodically to assess the need and timing for additional generating capacity and interconnections. These reviews consider existing and projected demand, the availability and price of power, the location of new load, and the economy. Summer peak load in the Entergy System service territory has averaged 21,03621,296 MW from 2002-2009.2002-2012. In the 2002 time period the Entergy System's long-term capacity resources, allowing for an adequate reserve margin, were approximately 3,000 MW less than the total capacity required for peak period demands. In this time period the Entergy System met its capacity shortages almost entirely through short-term power purchases in the wholesale spot market. In the fall of 2002 the Entergy System began a program to add new resources to its existing generation portfolio and began a process of issuing requests for proposals (RFP) to procure supply-side resources from sources other than the spot market to meet the unique regional needs of the Utility operating companies. The Entergy System has adopted a long-term resource strategy that calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. The SystemEntergy refers to this strategy as "The Portfoliothe "Portfolio Transformation Strategy". Over the past eighteleven years, Portfolio Transformation has resulted in the addition of about 4,0005,992 MW of new long-term resources. This figure does not include transactions currently pending as a result of the 2012 Renewable RFP, Preliminary IRP Sustainability Projects, or the uprate of Grand Gulf. The uprate at Grand Gulf has been approved and reflected in the Winter Rating of 1,463 MW as of December 31, 2012, but a Summer Rating has yet to be approved for Summer 2013. When the 2012 Renewable RFP transactions are included in the Entergy System portfolio of long-term resources including approximately 900 MW of resources that are currently under regulatory review. Adjustingand adjusting for unit deactivations of older generation, currently, the System's portfolio of long-term resourcesEntergy System is about 1,500approximately 370 MW short of its projected 20102013 peak load plus reserve
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margin. TheThis remaining need has beenis expected to be met withthrough the Grand Gulf Uprate, not reflected in the Summer 2012 rating, and limited-term resource procurements.resources. The Entergy System will continue to access the spot power market to economically purchase energy in order to minimize customer cost.cost; however, the Utility operating companies plan to join the MISO RTO beginning December 19, 2013 and upon integration expect to have access to the MISO Day 2 market. In addition, Entergy considers in its planning processes the implications of the notices from Entergy Arkansas and Entergy Mississippi regarding their future withdrawal from the System Agreement. Furthermore, as with other transmission systems, there are certain times during which congestion occurs on the Utility operating companies' transmission system that limits the ability of the Utility operating companies as well as other parties to fully utilize the generating resources that have been granted transmission service.
RFP Procurements
The RFPs issued by the Entergy System since the fall of 2002 have sought resources needed to meet near-term summer reliability requirements as well as longer-term resourcesrequirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. Detailed evaluation processes have been developed to analyze submitted proposals, and, with the exception of the January 2008 RFP, and the 2008 Western Region RFP, the 2010 Renewable RFP, and the 2011 Entergy Arkansas RFP, each RFP has been overseen by an independent monitor. The following table illustrates the results of the RFP process for resources acquired since the Fall 2002 RFP. The contracts below were primarily with non-affiliated suppliers,
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with the exception of contracts with EWO Marketing for the sale of 185 MW to 206 MW from the RS Cogen plant, and contracts with Entergy Power for the sale of approximately 100 MW from the Independence plant. In 2009,plant, and an MSS-4 agreement between Entergy Louisiana requested permission fromArkansas and Entergy Mississippi for the LPSC to cancel the Little Gypsy Unit 3 re-powering project selected from the 2006 Long-Term RFP.purchase of approximately 60 MW of Grand Gulf capacity and energy (with deliveries starting January 1, 2013).
RFP | | Short-term 3rd Short- term 3rd party | | Limited-term affiliate | | Limited-term 3rd Limited- term 3rd party | | Long-term affiliate | | Long-term 3rd party | | Total |
| | | | | | | | | | | | | |
| Fall 2002 | | - | | 185-206 MW (a) | | 231 MW | | 101-121 MW (b) | | 718 MW (d) | | 1,235-1,276 MW |
January 2003 supplemental | | 222 MW | | - | | - | | - | | - | | 222 MW |
| Spring 2003 | | - | | - | | 381 MW | | (c) | | - | | 381 MW |
| Fall 2003 | | - | | - | | 390 MW | | - | | - | | 390 MW |
| Fall 2004 | | - | | - | | 1,250 MW | | - | | - | | 1,250 MW |
| 2006 Long-Term | | - | | - | | - | | 538 MW (e) | | 789 MW (f) | | 1,327 MW |
| Fall 2006 | | - | | - | | 780 MW | | - | | - | | 780 MW |
| January 2008 (g) | | - | | - | | - | | - | | - | | - |
| 2008 Western Region | | | | | | | | | | | | |
| Summer 2008 (h) | | - | | - | | 200 MW | | - | | - | | 200 MW |
| January 2009 Western Region | | - | | -
| | -
| | -
| | 150-300
| | 150-300 MW
|
July 2009 Baseload | | - | | 336 MW (i) | | - | | | | | | |
Summer 2009 (j) | | - | | - | | - | | TBD- | | TBD | | TBD |
Total | | 222150-300 MW | | 521-542150-300 MW |
| July 2009 Baseload | | - | | 336 MW (i) | | - | | - | | - | | 336 MW |
| Summer 2009 Long-Term (j) | | - | | - | | - | | 551 MW | | 3,5321,555 MW | | 639-6592,106 MW |
| 2010 Renewable RFP (k) | | - | | - | | - | | - | | 28-37 MW (l) | | 28-37 MW |
| 2011 Entergy Arkansas RFP | | - | | - | | 495 MW | | 1,657-1,807- | | - | | 495 MW |
| 2012 Baseload RFP (m) | | - | | - | | - | | 60 MW | | 6,571-6,762- | | 60 MW |
| (a) | Includes a conditional option to increase the capacity up to the upper bound of the range. |
| (b) | The contracted capacity will increaseincreased from 101 MW to 121 MW in 2010. |
| (c) | This table does not reflect (i) the River Bend 30% life-of-unit purchased power agreements totaling approximately 300 MW between Entergy Gulf States Louisiana and Entergy Louisiana (200 MW), and between Entergy Gulf States Louisiana and Entergy New Orleans (100 MW) related to Entergy Gulf States Louisiana's unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun Electric Power Cooperative, Inc. or (ii) the Entergy Arkansas wholesale base load capacity life-of-unit purchased power agreements executed in 2003 totaling approximately 220 MW between Entergy Arkansas and Entergy Louisiana (110 MW) and between Entergy Arkansas and Entergy New Orleans (110 MW) related to the sale of a portion of Entergy Arkansas'Arkansas’s coal and nuclear base load resources (which were not included in retail rates); or (iii) 12 month12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Gulf States Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating to the sale of a portion of Entergy Arkansas'Arkansas’s coal and nuclear base load resources (which were not included in retail rates) to those companies. These resources were identified outside of the formal RFP process but were submitted as formal proposals in response to the Spring 2003 RFP, which confirmed the economic merits of these resources. |
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| (d) | Entergy Louisiana's June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which a total of 75% of the output is sold to Entergy Gulf States Louisiana and Entergy Texas. |
| (e) | In 2009, Entergy Louisiana requested permission from2011, the LPSC to cancelapproved Entergy Louisiana’s cancellation of the Little Gypsy Unit 3 re-powering project.project selected from the 2006 Long-Term RFP. |
| (f) | Entergy Arkansas'Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility, of which one-third of the output was sold to Entergy Gulf States Louisiana prior to the purchase of one-third of the facility by Entergy Gulf States Louisiana in November 2009. |
| (g) | At the direction of the LPSC, but with full reservation of all legal rights, Entergy Services issued the January 2008 RFP for Supply-Side Resources seeking fixed price unit contingent products. Although the LPSC request was directed to Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the RFP on behalf of all of the Utility operating companies. No proposals were selected from this RFP. |
| (h) | OnIn October 15, 2008, and in response to the USU.S. financial crisis, ESIEntergy Services on behalf of the Entergy Operating CompaniesUtility operating companies terminated all long-term procurement efforts, including the long-term portion of the Summer 2008 RFP. |
| (i) | Represents the self-supply alternative considered in the RFP, consisting of a cost-based purchase by Entergy Texas, Entergy Louisiana, and Entergy Mississippi of wholesale baseload capacity from Entergy Arkansas. |
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| (j) | In September 2009, on behalfIncludes the Ninemile self-build option, acquisitions from KGen of its Hinds and Hot Spring facilities, and a long-term PPA with Calpine Carville. |
| (k) | Two additional transactions resulting from the Entergy operating companies, Entergy Services issued2010 Renewable RFP are still pending and are not reflected in the Summer 2009 Long-Term RFP seeking proposals for long-termtable. |
| (l) | Includes a 28 MW purchase of baseload capacity and energy through products offeredfrom a new electric generation waste heat recovery facility (Rain) located in Sulphur, Louisiana, with the RFP. Thepotential for the purchase of nine additional megawatts from the facility subject to availability. As of December 31, 2012, the Rain facility had not yet achieved commercial operation. |
| (m) | Only includes the agreement resulting from the RFP includes a Utility self-build option. The tentative RFP schedule targets resource selection in the third quarter 2010for Entergy Mississippi to purchase capacity and execution of definitive agreements by the fourth quarter 2010.energy from Entergy Arkansas from Grand Gulf (60 MW). |
Entergy Louisiana and Entergy New Orleans currently purchase, 101pursuant to ten-year purchased power agreements that expire in 2013, 121 MW of capacity and energy from Entergy Power Inc. sourced from Independence Steam Electric Station Unit 2.2 (ISES 2). The transaction, which originated from the Fall 2002 RFP, included an option for Entergy Louisiana and Entergy New Orleans to acquire an ownership interest in the unit for a total price of $80 million, subject to various adjustments. OnIn March 5, 2008, Entergy Louisiana and Entergy New Orleans provided notice of their intent to exercise the option. The parties are negotiatingBased upon changes in the terms and conditionslong-term economics of the resource relative to current options, in August 2011, Entergy Louisiana made a filing with the LPSC seeking relief from a prior LPSC directive to exercise the option to purchase an ownership acquisition.interest in the Independence unit. On May 10, 2012, the LPSC issued an order rescinding the LPSC’s previous directive to Entergy Louisiana to exercise its option to purchase an ownership interest in ISES 2. Because the City Council had not issued a comparable directive, Entergy New Orleans was not required to seek comparable relief from the City Council; however, Entergy New Orleans has indicated to the Council Advisors that it did not intend to proceed with acquiring an ownership interest in ISES 2 at the termination of the purchased power agreement.
In JanuaryJune 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a nominally-sized 550 MW combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station that was selected in the Summer 2009 Entergy Texas issued an RFP seeking long-term CCGT resources for the Western RegionLong-Term RFP. For additional discussion of the Ninemile 6 project see “Capital Expenditure Plans and Other Uses of Capital” in Entergy System in pursuit of multiple supply procurement objectives. As a result of the RFP, Entergy Services, as agent for Entergy Texas, has signed a PPA with Exelon Generation Company, LLC to purchase 150-300 megawatts of capacityCorporation and energy from the Tenaska Frontier Generating Station located in Grimes County, Texas. The PPA has an approximately ten-year delivery termSubsidiaries Management’s Financial Discussion and may be terminated by Entergy Texas if necessary regulatory approvals, including full cost recovery, are not obtained.Analysis.
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In July 2009,December 2010, on behalf of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Services issued the July 2009 Baseload2010 RFP for Long-Term Renewable Energy Resources seeking up to 233 MW of renewable generation resources to meet the requirements of an LPSC general order issued in December 2010. In September 2012, Entergy Gulf States Louisiana executed a 20-year contract for 28 MW, with the potential to purchase an additional nine megawatts when available, from Rain being constructed at the Rain pet coke calcining facility in Sulphur, Louisiana. The facility is expected to begin commercial operations in early 2013. LPSC certification of the contract was received on December 12, 2012. As of December 31, 2012, Entergy Services was in negotiations to reach definitive agreement(s) associated with two other proposals selected in the RFP.
In June 2011, on behalf of Entergy Arkansas, Entergy Services issued the 2011 RFP for Transition Plan Resources. The RFP sought up to 750 MW of flexible generation resources through one or more purchased power agreements to address Entergy Arkansas’s requirements for its 2014-2016 time frame. Entergy Arkansas concluded its review and evaluation of the proposals submitted in response to the RFP in November 2011 and selected two proposals totaling approximately 795 MW for negotiation of definitive agreements. In October 2012, Entergy Arkansas and Union Power Partners, L.P. executed a 3 ½ year agreement for 495 MW from the Union Power Station located in El Dorado, Arkansas, subject to regulatory approval. The agreement is under review by the APSC and cost recovery for this purchased power agreement will be determined as part of Entergy Arkansas’s general rate case that will be filed in March 2013.
In December 2011, on behalf of Entergy Texas, Entergy Services issued the 2011 Western Region RFP for Long-Term Supply Side Resources. This RFP sought approximately 300 MW of baseload or flexible capacity, energy, and other electric products to meet the long-term reliability needs of the Western Region beginning in 2017 and included a self-build option at Entergy Texas’s Lewis Creek site. On November 2, 2012, Entergy Services announced that one proposal had been selected for award and the negotiation of a definitive agreement, and a secondary proposal had been placed on the secondary selection list.
In August 2012, Entergy Services issued a request for proposals for long-term, stable price, baseload resources on behalf of Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, Entergy Texas, and Entergy Mississippi seeking limited-term flexibleMississippi. The RFP sought between 50 and 150 MW of baseload resources. Acapacity through a PPA commencing in 2013 for a minimum of 10 years up to life of unit. As part of the RFP process, Entergy Services market-tested a self-supply alternative, which was considered and ultimately selecteda cost-based purchase of 60 MW from Entergy Arkansas’s share of Grand Gulf. Based on the RFP evaluation results, in November 2012, Entergy elected to proceed with the self-supply alternative and consistselected not to move forward with any other proposal. The capacity and associated energy was subsequently allocated to Entergy Mississippi, and MPSC and FERC approval was received for the transaction in December 2012. Entergy Mississippi also transacted for an additional 30 MW purchase, which did not come through the RFP process, of a 336 MW limited-term cost-based wholesale baseload purchasecapacity and energy from Entergy Arkansas.Arkansas’s share of Grand Gulf. Deliveries under both agreements, totaling 90 MW, began on January 1, 2013, and cost recovery for the 90 MW was approved by the MPSC in January 2013.
Other Procurements From Third Parties
The above table does not include resource acquisitions made outside of the RFP process, including Entergy Mississippi's January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant, andplant; Entergy Gulf States Louisiana's March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility. In addition, in October 2009Facility; and Entergy Louisiana, LLC entered into a Purchase and Sale Agreement to acquire Unit 2Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center a 580 MW generating unit located near Eunice, Louisiana from Acadia Power Partners, LLC, an independent power producer. The purchase is contingent on regulatory approvals.Unit 2. The above table also does not reflect various limited- and long-term contracts that have been entered into in recent years by the Utility operating companies as a result of bilateral negotiations.
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Interconnections
The Entergy System's generating units are interconnected by a transmission system operating at various voltages up to 500 kV. These generating units consist primarily of steam-electric production facilities and are centrally dispatched and operated. Entergy's Utility operating companies are interconnected with many neighboring utilities. In addition, the Utility operating companies are members of the SERC Reliability Corporation. The primary purpose of SERC is to ensure the reliability and adequacy of the electric bulk power supply in the southeast region of the United States. SERC is a member of the North American Electric Reliability Corporation.
Gas Property
As of December 31, 2009,2012, Entergy New Orleans distributed and transported natural gas for distribution within Algiers and New Orleans, Louisiana, through a total of 33approximately 2,500 miles of gas transmission pipeline, 1,655 miles of gas distribution pipeline, and 855 miles of gas service pipeline from the distribution mains to the customers.pipeline. As of December 31, 2009,2012, the gas properties of Entergy Gulf States Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Gulf States Louisiana's financial position.
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TitlesTitle
The Entergy System's generating stations are generally located on properties owned in fee simple. Most of the substations and transmission and distribution lines are constructed on private property or public rights-of-way pursuant to easements, servitudes, or appropriate franchises. Some substation properties are owned in fee simple. The Utility operating companies generally have the right of eminent domain, whereby they may perfect title to, or secure easements or servitudes on, private property for their utility operations.
Substantially all of the physical properties and assets owned by Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are subject to the liens of mortgages securing bonds issued by those companies. The Lewis Creek generating station is owned by GSG&T, Inc., a subsidiary of Entergy Texas, and is not subject to its mortgage lien. Lewis Creek is leased to and operated by Entergy Texas.
Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2007-20092010-2012 were:
| | | Natural Gas | | Fuel Oil | | Nuclear | | Coal | | Purchased Power |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
| | | | | | | | | | | | | | | | | | | | | |
| 2009 | | 19 | | 5.64 | | - | | - | | 34 | | .66 | | 12 | | 2.04 | | 35 | | 5.29 |
| 2008 | | 19 | | 10.28 | | - | | 19.45 | | 30 | | .60 | | 12 | | 2.06 | | 39 | | 7.92 |
| 2007 | | 18 | | 8.05 | | - | | 14.13 | | 33 | | .57 | | 12 | | 1.86 | | 37 | | 6.27 |
| | | Natural Gas | | Nuclear | | Coal | | Purchased Power |
Year | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
| | | | | | | | | | | | | | | | | |
| 2012 | | 27 | | 3.15 | | 33 | | .85 | | 11 | | 2.60 | | 29 | | 3.58 |
| 2011 | | 25 | | 4.85 | | 34 | | .81 | | 13 | | 2.31 | | 28 | | 4.59 |
| 2010 | | 22 | | 5.39 | | 36 | | .78 | | 13 | | 2.00 | | 29 | | 5.28 |
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Actual 20092012 and projected 20102013 sources of generation for the Utility operating companies and System Energy, including certain power purchases from affiliates under life of unit power purchase agreements, including the Unit Power Sales Agreement, are:
| | Natural Gas | | Fuel Oil | | Nuclear | | Coal | | Purchased Power |
| | 2009 | | 2010 | | 2009 | | 2010 | | 2009 | | 2010 | | 2009 | | 2010 | | 2009 | | 2010 |
| | | | | | | | | | | | | | | | | | | | |
Entergy Arkansas (a) | 3% | | 12% | | - | | - | | 46% | | 48% | | 24% | | 25% | | 26% | | 14% |
Entergy Gulf States Louisiana | | | | | | | | | | | | | | | | | | | |
Entergy Louisiana | 22% | | 19% | | - | | - | | 36% | | 44% | | 2% | | 2% | | 40% | | 35% |
Entergy Mississippi | 25% | | 48% | | - | | - | | 3% | | 3% | | 21% | | 29% | | 51% | | 20% |
Entergy New Orleans | 34% | | 40% | | - | | - | | 22% | | 31% | | 9% | | 14% | | 35% | | 15% |
Entergy Texas | 36% | | 28% | | - | | - | | 13% | | 20% | | 10% | | 13% | | 41% | | 39% |
| System Energy | - | | - | | - | | - | | 100%(b) | | 100%(b) | | - | | - | | - | | - |
| | | | | | | | | | | | | | | | | | | | |
| Utility (a) | 19% | | 22% | | - | | - | | 34% | | 36% | | 12% | | 13% | | 35% | | 29% |
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Entergy Corporation, Utility operating companies, and System Energy| | | Natural Gas | | Nuclear | | Coal | | Purchased Power |
| | | 2012 | | 2013 | | 2012 | | 2013 | | 2012 | | 2013 | | 2012 | | 2013 |
| | | | | | | | | | | | | | | | | |
| Entergy Arkansas (a) | | 6% | | 9% | | 56% | | 56% | | 23% | | 21% | | 15% | | 13% |
| Entergy Gulf States Louisiana | | 32% | | 36% | | 29% | | 15% | | 8% | | 10% | | 31% | | 39% |
| Entergy Louisiana | | 33% | | 26% | | 32% | | 44% | | 2% | | 1% | | 33% | | 29% |
| Entergy Mississippi | | 43% | | 44% | | 17% | | 25% | | 19% | | 18% | | 21% | | 13% |
| Entergy New Orleans | | 38% | | 30% | | 40% | | 54% | | 9% | | 6% | | 13% | | 10% |
| Entergy Texas | | 31% | | 20% | | 12% | | 15% | | 7% | | 10% | | 50% | | 55% |
| System Energy (b) | | - | | - | | 100% | | 100% | | - | | - | | - | | - |
| Utility (a) | | 27% | | 25% | | 33% | | 35% | | 11% | | 11% | | 29% | | 29% |
| (a) | Hydroelectric power provided less than 1% of Entergy Arkansas'Arkansas’s generation in 20092012 and is expected to provide approximatelyless than 1% of its generation in 2010.2013. |
| (b) | Capacity and energy from System Energy'sEnergy’s interest in Grand Gulf was historicallyis allocated as follows:follows under the Unit Power Sales Agreement: Entergy Arkansas - 36%; Entergy Louisiana - 14%; Entergy Mississippi - 33%; and Entergy New Orleans - 17%. Pursuant to purchased power agreements, Entergy Arkansas is selling a portion of its owned capacity and energy from Grand Gulf to Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. |
Some of the Utility’s gas-fired plants are capable of also using fuel oil, if necessary. Although based on current economics the Utility does not expect fuel oil use in 2013, it is possible that various operational events including weather or pipeline maintenance may require the use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and gas transportation. Long-term firm contracts for power plants comprise less than 15%25% of the Utility operating companies' total requirements. Short-term contracts and spot-market purchases satisfy additional gas requirements. Entergy Texas owns a gas storage facility that provides reliable and flexible natural gas service to certain generating stations.
Entergy Louisiana hasentered into a long-term natural gas supply contract which expires in 2012,beginning January 1, 2013, in which Entergy Louisiana agreed to purchasepurchases natural gas in annual amounts equal to approximately one-third of its projected annual fuel requirements for certain generating units. Annual demand charges associated with this contract are estimated to be $6.6 million.
Many factors, including wellhead deliverability, storage and pipeline capacity, and demand requirements of end users, influence the availability and price of natural gas supplies for power plants. Demand is tied to weather conditions as well as to the prices and availability of other energy sources. Pursuant to federal and state regulations, gas supplies to power plants may be interrupted during periods of shortage. To the extent natural gas supplies are disrupted or natural gas prices significantly increase, the Utility operating companies will use alternate fuels, such as oil, or rely to a larger extent on coal, nuclear generation, and purchased power.
Coal
Entergy Arkansas has a long-term contract for low-sulfur Powder River Basin (PRB) coal which expires in 2011 and is expected to provide for approximately 40% of the total expected coal requirements for 2010. Over the past three years, Entergy Arkansas has committed to seven medium-term (one-four one- to three-year)three-year contracts that will supply approximately 55%90% of the total coal supply needs in 2010.2013. These contracts are staggered in term so that not all contracts have to be renewed the same year. The additional 5%remaining 10% of total coal requirements will be satisfied by spot market or over-the-counter purchases.contracts with a term of less than one year. Based on greater PRBcontinued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of foreign coal,alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2010.2013. Entergy Arkansas has an existing long-term railroad transportation contract that willis expected to provide all of Entergy Arkansas'Arkansas’s coal transportation requirements for 20102013.
Part I Item 1
Entergy Corporation, Utility operating companies, and will provide most of the transportation requirements for several years beyond 2010.System Energy
Entergy Gulf States Louisiana has executed three medium-termone- to three-year contracts for the supply of low-sulfur PRB coal for Nelson Unit 6 that will expire in late 2010 and 2011. These three contracts will supply approximately 95%90% of Nelson Unit 6 coal needs in 2010.2013. Additional PRB coal will be purchased through spot market or over-the-counter purchases provided that adequate transportation is available from BNSF Railway Company.contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas'Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2010.2013. Coal will be transported to Nelson via an existing transportation agreement that is expected to provide all of Entergy Gulf States Louisiana’s rail transportation agreement with BNSF Railway Company during 2010.requirements for 2013.
For the year 2009,2012, coal transportation delivery to all Utility operating companyEntergy Arkansas and Entergy Gulf States Louisiana operated coal-fired units have met coal demand at the plants. Itplants and it is expected that improved delivery times experienced in 20092012 will continue through 2010.2013. Both Entergy Arkansas and Entergy Gulf States Louisiana control a sufficient number of railcars to satisfy the rail transportation requirement.
The operator of Big Cajun 2 - Unit 3, Louisiana Generating, LLC, has advised Entergy Gulf States Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of low-sulfur PRB coal requested for 2010.2013. Entergy Gulf States LouisianaLouisiana’s and Entergy TexasTexas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
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Entergy Corporation, Utility operating companies, and System Energy
Nuclear Fuel
The nuclear fuel cycle consists of the following:
| · | mining and milling of uranium ore to produce a concentrate; |
| · | conversion of the concentrate to uranium hexafluoride gas; |
| · | enrichment of the uranium hexafluoride gas; |
| · | fabrication of nuclear fuel assemblies for use in fueling nuclear reactors; and |
| · | disposal of spent fuel. |
System Fuels, a company owned by EntergyThe Registrant Subsidiaries that own nuclear plants (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Mississippi,Louisiana, and Entergy New Orleans, isSystem Energy), are responsible through a shared regulated uranium pool for contracts to acquire nuclear material to be used in fueling Entergy's Utility nuclear units, exceptunits. These companies own the materials and services in this shared regulated uranium pool on a pro rata fractional basis determined by the nuclear generation capability of each company. Any liabilities for River Bend. System Fuels alsoobligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of suchnuclear materials during the various stages of processing. The Utility operating companies, except Entergy Gulf States Louisiana,Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from System Fuels, but contractthe shared regulated uranium pool. Entergy Operations Inc. contracts separately for the fabrication of their own nuclear fuel. The requirements for River Bend are met pursuant to contracts made by Entergy Gulf States Louisiana.fuel as agent on behalf of each of the Registrant Subsidiaries that owns a nuclear plant. All contracts for the disposal of spent nuclear fuel are between the Department of Energy (DOE) and eachthe owner of thea nuclear power plants.plant.
Based upon currently planned fuel cycles, Entergy'sthe nuclear units in both the Utility and Non-Utility Nuclear nuclear unitsEntergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 2010, and with substantial additional amounts after that time. Entergy's2013. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the creditworthiness and performance reliability of uranium miners, as well as upon the structure of Entergy's contracts for the purchase of nuclear fuel. For example, some of the supply under Entergy's contracts for nuclear fuel is effectively on a "mine-contingent" basis, which means that if applicable mines are unable to supply sufficient uranium, Entergy may be required to purchase some nuclear fuel from another supplier.miners. There are a number of possible alternate suppliers that may be accessed to mitigate such an event,any supplier performance failure, including potentially drawing upon Entergy'sEntergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. In addition, some nuclear fuel contracts are on a non-fixed price basis subject to prevailing prices at the time of delivery.
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Entergy Corporation, Utility operating companies, and 2007, but this supply shortfall was substantially eliminated in 2008. Market prices for uranium concentrates increased from about $7 per pound in December 2000 to a range of $70 to $135 per pound in 2007. In 2008, however, market prices for uranium concentrates ranged from $45 to $90 per pound and from January 1, 2009 through December 31, 2009 ranged from $40 to $55 per pound. System Energy
The effects of market price changes may be reduced and deferred by risk management strategies, (suchsuch as negotiation of floor and ceiling amounts for long-term contracts, buying for inventory or entering into forward physical contracts at fixed prices when Entergy believes it is appropriate and useful).useful. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S.
The recent higher nuclear fuel market prices of 2006-2009 compared to the 2000-2005 period affects the U.S. nuclear utility industry, including Entergy, first in cash flow requirements for fuel acquisition, and then, some time later, in nuclear fuel expenses. For example, for a nuclear fleet the size of Entergy's, the current market value of annual enriched uranium requirements has increased by several hundred million dollars compared to about five years ago. As nuclear fuel installed in the core in nuclear power plants is replaced fractionally over an approximate five-year period, nuclear fuel expense is beginning to, and will eventually with a time lag, reflect current market prices and can be expected to increase from the previously reported industry levels of about 0.5 cents per kWh to closer to 1.0 cent per kWh. Entergy's nuclear fuel contract portfolio has provided a degree of price hedging against the full extent of market prices through 2010, but market trends will eventually affect the costs of all nuclear plant operators.
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Entergy Corporation, Utility operating companies, and System Energy
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy each have made arrangements to lease nuclear fuel and related equipment and services. The lessors, which are consolidated in the financial statements of Entergy and the applicable Registrant Subsidiary, finance the acquisition and ownership of nuclear fuel through credit agreements and the issuance of notes. These arrangements are subject to periodic renewal. See Note 10 to the financial statements for a discussion of nuclear fuel leases.
Natural Gas Purchased for Resale
Entergy New Orleans has several suppliers of natural gas. Its system is interconnected with three interstate and three intrastate pipelines. Entergy New Orleans has a "no-notice" service gas purchase contract with Atmos Energy which guarantees Entergy New Orleans gas delivery at specific delivery points and at any volume within the minimum and maximum set forth in the contract amounts. The Atmos Energy gas supply is transported to Entergy New Orleans pursuant to a transportation service agreement with Gulf South Pipeline Co. This service is subject to FERC-approved rates. Entergy New Orleans also makes interruptible spot market purchases. In recent years, natural gas deliveries to Entergy New Orleans have been subject primarily to weather-related curtailments.
Entergy Gulf States Louisiana purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. The gas is delivered through a combination of intrastate and interstate pipelines.
As a result of the implementation of FERC-mandated interstate pipeline restructuring in 1993, curtailments of interstate gas supply could occur if Entergy Gulf States Louisiana’s or Entergy New Orleans'Orleans's suppliers failed to perform their obligations to deliver gas under their supply agreements. Gulf South Pipeline Co. could curtail transportation capacity only in the event of pipeline system constraints.
Entergy Gulf States Louisiana purchases natural gas for resale under a firm contract from Enbridge Marketing (U.S.) Inc. In August 2008, Entergy Gulf States Louisiana entered into a new five-year contract with Enbridge Marketing (U.S.) Inc. The gas is delivered through a combination of intrastate and interstate pipelines.
Federal Regulation of the Utility
State or local regulatory authorities, as described above, regulate the retail rates of the Utility operating companies. The FERC regulates wholesale rates (including intrasystem sales pursuant to the System Agreement) and interstate transmission of electricity, as well as rates for System Energy'sEnergy’s sales of capacity and energy from Grand Gulf to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans pursuant to the Unit Power Sales Agreement.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources are jointly operated by the Utility operating companies. The System Agreement provides, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shall receive payments from those parties having generating reserves that are less than their allocated share of reserves (short companies). Such payments are at amounts sufficient to cover certain of the long companies'companies’ costs for intermediate and peaking oil/gas-fired generation, including operating expenses, fixed charges on debt, dividend requirements on preferred equity, and a fair rate of return on common equity investment. Under the System Agreement, these chargesthe rates used to compensate long companies are based on costs associated with the long companies'companies’ steam electric generating units fueled by oil or gas and having an annual average heat rate above 10,000 Btu/kWh. In addition, for all energy exchanged among the Utility operating companies under the System Agreement, the companies purchasing exchange energy are required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs.
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Citing its concerns that the benefits of its continued participation in the current form of the System Agreement have been seriously eroded, in December 2005, Entergy Arkansas submitted its notice that it will terminate its participation in the current System Agreement effective ninety-six (96) months from the date of the notice or such earlier date as authorized by the FERC. Entergy Arkansas indicated, however, that a properly structured replacement agreement could be a viable alternative. In November 2007, pursuant to the provisions of the System Agreement, Entergy Mississippi provided its written notice to terminate its participation in the System Agreement effective ninety-six (96) months from the
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Entergy Corporation, Utility operating companies, and System Energy
date of the notice or such earlier date as authorized by the FERC. In light of the notices of Entergy Arkansas and Entergy Mississippi to terminate participation in the current System Agreement, in January 2008 the LPSC unanimously voted to direct the LPSC Staff to begin evaluating the potential for a new agreement. Likewise, the New Orleans City Council opened a docket to gather information on progress towards a successor agreement.
In November 2009 the FERC accepted the notices of cancellation and determined that Entergy Arkansas and Entergy Mississippi are permitted to withdraw from the System Agreement following the 96 month96-month notice period without payment of a fee or being requiredthe requirement to otherwise compensate the remaining Utility operating companies as a result of withdrawal. TheIn February 2011 the FERC stated it expected Entergydenied the LPSC’s and all interested parties to move forward and develop details of all needed successor arrangements and encouraged Entergy to file its Section 205 filing for post 2013 arrangements as soon as possible.the City Council’s rehearing requests. The LPSC and the City Council have requestedappealed the FERC’s decision to the U.S. Court of Appeals for the D.C. Circuit. The D.C. Circuit denied the appeal and in September 2012 the LPSC filed a petition for rehearing and rehearing en banc with the D.C. Circuit. In October 2012 the D.C. Circuit denied the LPSC’s request for rehearing and rehearing en banc. In January 2013 the LPSC filed a petition for a writ of certiorari with the FERC's decision.U.S. Supreme Court.
See "“System Agreement Proceedings"” in Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of the proceedings at the FERC involving the System Agreement and other related proceedings.
Transmission
See "Independent Coordinator of Transmission" in the "“Rate, Cost-recovery, and Other RegulationPlan to Spin Off the Utility’s Transmission Business"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis.
See “Independent Coordinator of Transmission” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
System Energy and Related Agreements
System Energy recovers costs related to its interest in Grand Gulf through rates charged to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans for capacity and energy under the Unit Power Sales Agreement (described below). In December 1995, System Energy commenced a rate proceeding at the FERC. In July 2001 the rate proceeding became final, with the FERC approving a prospective 10.94% return on equity. The FERC'sFERC’s decision also affected other aspects of System Energy'sEnergy’s charges to the Utility operating companies that it supplies with power. In 1998 the FERC approved requests by Entergy Arkansas and Entergy Mississippi to accelerate a portion of their Grand Gulf purchased power obligations. Entergy Arkansas'Arkansas’s and Entergy Mississippi'sMississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC.
Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System Energy's current 90%Energy’s ownership and leasehold interests in Grand Gulf to Entergy Arkansas (36%), Entergy Louisiana (14%), Entergy Mississippi (33%), and Entergy New Orleans (17%). Each of these companies is obligated to make payments to System Energy for its entitlement of capacity and energy on a full cost-of-service basis regardless of the quantity of energy delivered, so long as Grand Gulf remains in commercial operation.delivered. Payments under the Unit Power Sales Agreement are System Energy'sEnergy’s only source of operating revenue. The financial condition of System Energy depends upon the continued commercial operation of Grand Gulf and the receipt of such payments. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans generally recover payments made under the Unit Power Sales Agreement through rates charged to their customers.
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In the case of Entergy Arkansas and Entergy Louisiana, payments are also recovered through sales of electricity from their respective retained shares of Grand Gulf. Under a settlement agreement entered into with the APSC in 1985 and amended in 1988, Entergy Arkansas retains 22% of its 36% share of Grand Gulf-related costs and recovers the remaining 78% of its share in rates. In the event that Entergy Arkansas is not able to sell its retained share to third parties, it may sell such energy to its retail customers at a price equal to its avoided cost, which is currently less than Entergy Arkansas'Arkansas’s cost from its retained share. Entergy Arkansas has life-of-resources purchased power agreements with Entergy Louisiana and Entergy New Orleans that sell a portion of the output of Entergy Arkansas'Arkansas’s retained share of Grand Gulf to those companies. In a series of LPSC orders, court decisions, and
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Entergy Corporation, Utility operating companies, and System Energy
agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy Louisiana'sLouisiana’s share of capacity and energy from Grand Gulf, subject to certain terms and conditions. Entergy Louisiana retains and does not recover from retail ratepayers 18% of its 14% share of the costs of Grand Gulf capacity and energy and recovers the remaining 82% of its share in rates. Entergy Louisiana is allowed to recover through the fuel adjustment clause at 4.6 cents per kWh for the energy related to its retained portion of these costs. Alternatively, Entergy Louisiana may sell such energy to non-affiliated parties at prices above the fuel adjustment clause recovery amount, subject to the LPSC'sLPSC’s approval.
Availability Agreement
The Availability Agreement among System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans was entered into in 1974 in connection with the financing by System Energy of Grand Gulf. The Availability Agreement provides that System Energy make available to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans all capacity and energy available from System Energy'sEnergy’s share of Grand Gulf.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans also agreed severally to pay System Energy monthly for the right to receive capacity and energy from Grand Gulf in amounts that (when added to any amounts received by System Energy under the Unit Power Sales Agreement) would at least equal System Energy'sEnergy’s total operating expenses for Grand Gulf (including depreciation at a specified rate)rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges. The September 1989 write-off of System Energy'sEnergy’s investment in Grand Gulf 2, amounting to approximately $900 million, is being amortized for Availability Agreement purposes over 27 years.
The allocation percentages under the Availability Agreement are fixed as follows: Entergy Arkansas - 17.1%; Entergy Louisiana - 26.9%; Entergy Mississippi - 31.3%; and Entergy New Orleans - 24.7%. The allocation percentages under the Availability Agreement would remain in effect and would govern payments made under such agreement in the event of a shortfall of funds available to System Energy from other sources, including payments under the Unit Power Sales Agreement.
System Energy has assigned its rights to payments and advances from Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under the Availability Agreement as security for its first mortgage bonds and reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under "“Sale and Leaseback Transactions - Grand Gulf Lease Obligations."Obligations.” In these assignments, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans further agreed that, in the event they were prohibited by governmental action from making payments under the Availability Agreement (for example, if the FERC reduced or disallowed such payments as constituting excessive rates), they would then make subordinated advances to System Energy in the same amounts and at the same times as the prohibited payments. System Energy would not be allowed to repay these subordinated advances so long as it remained in default under the related indebtedness or in other similar circumstances.
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Entergy Corporation, Utility operating companies, and System Energy
Each of the assignment agreements relating to the Availability Agreement provides that Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans will make payments directly to System Energy. However, if there is an event of default, those payments must be made directly to the holders of indebtedness that are the beneficiaries of such assignment agreements. The payments must be made pro rata according to the amount of the respective obligations secured.
The obligations of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans to make payments under the Availability Agreement are subject to the receipt and continued effectiveness of all necessary regulatory approvals. Sales of capacity and energy under the Availability Agreement would require that the Availability Agreement be submitted to the FERC for approval with respect to the terms of such sale. No such filing with the FERC has been made because sales of capacity and energy from Grand Gulf are being made pursuant to the Unit Power Sales Agreement. If, for any reason, sales of capacity and energy are made in the future pursuant to the Availability Agreement, the jurisdictional portions of the Availability Agreement would be submitted to the FERC for approval.
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Since commercial operation of Grand Gulf began, payments under the Unit Power Sales Agreement to System Energy have exceeded the amounts payable under the Availability Agreement. Therefore, no payments under the Availability Agreement have ever been required. If Entergy Arkansas or Entergy Mississippi fails to make its Unit Power Sales Agreement payments, and System Energy is unable to obtain funds from other sources, Entergy Louisiana and Entergy New Orleans could become subject to claims or demands by System Energy or its creditors for payments or advances under the Availability Agreement (or the assignments thereof) equal to the difference between their required Unit Power Sales Agreement payments and their required Availability Agreement payments because their Availability Agreement obligations exceed their Unit Power Sales Agreement obligations.
The Availability Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, without further consent of any assignees or other creditors.
Capital Funds Agreement
System Energy and Entergy Corporation have entered into the Capital Funds Agreement, whereby Entergy Corporation has agreed to supply System Energy with sufficient capital to (i) maintain System Energy'sEnergy’s equity capital at an amount equal to a minimum of 35% of its total capitalization (excluding short-term debt) and (ii) permit the continued commercial operation of Grand Gulf and pay in full all indebtedness for borrowed money of System Energy when due.
Entergy Corporation has entered into various supplements to the Capital Funds Agreement. System Energy has assigned its rights under such supplements as security for its first mortgage bonds and for reimbursement obligations to certain banks providing letters of credit in connection with the equity funding of the sale and leaseback transactions described in Note 10 to the financial statements under "“Sale and Leaseback Transactions - Grand Gulf Lease Obligations."Obligations.” Each such supplement provides that permitted indebtedness for borrowed money incurred by System Energy in connection with the financing of Grand Gulf may be secured by System Energy'sEnergy’s rights under the Capital Funds Agreement on a pro rata basis (except for the Specific Payments, as defined below). In addition, in the supplements to the Capital Funds Agreement relating to the specific indebtedness being secured, Entergy Corporation has agreed to make cash capital contributions directly to System Energy sufficient to enable System Energy to make payments when due on such indebtedness (Specific Payments). However, if there is an event of default, Entergy Corporation must make those payments directly to the holders of indebtedness benefiting from the supplemental agreements. The payments (other than the Specific Payments) must be made pro rata according to the amount of the respective obligations benefiting from the supplemental agreements.
The Capital Funds Agreement may be terminated, amended, or modified by mutual agreement of the parties thereto, upon obtaining the consent, if required, of those holders of System Energy'sEnergy’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement.
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Entergy Corporation, Utility operating companies, and System Energy
Service Companies
Entergy Services, a corporation wholly-owned by Entergy Corporation, provides management, administrative, accounting, legal, engineering, and other services primarily to the Utility operating companies. Entergy Operations is also wholly-owned by Entergy Corporation and provides nuclear management, operations and maintenance services under contract for ANO, River Bend, Waterford 3, and Grand Gulf, subject to the owner oversight of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, respectively. Entergy Services and Entergy Operations provide their services to the Utility operating companies and System Energy on an "at cost"“at cost” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
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Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Management believes that the jurisdictional separation will better align Entergy Gulf States, Inc.'s Louisiana and Texas operations to serve customers in those states and to operate consistent with state-specific regulatory requirements as the utility regulatory environments in those jurisdictions evolve. The jurisdictional separation provides for regulation of each separated company by a single retail regulator, which should reduce regulatory complexity.
Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.'s’s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Gulf States Louisiana remains primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, of which $168 million remains outstanding at December 31, 2009. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation. Entergy Texas' debt assumption does not discharge Entergy Gulf States Louisiana's liability for the long-term debt. To secure its debt assumption obligations, Entergy Texas granted to Entergy Gulf States Louisiana a first lien on Entergy Texas' assets that were previously subject to the Entergy Gulf States, Inc. mortgage. Entergy Texas has until December 31, 2010 to repay the assumed debt. In addition, Entergy Texas, as the owner of Entergy Gulf States Reconstruction Funding I, LLC ("EGSRF I"), reports the $329.5 million of senior secured transition bonds ("securitization bonds") issued by EGSRF I as long-term debt on its consolidated balance sheet. The securitization bonds are non-recourse to Entergy Texas.
Entergy Texas will purchasepurchases from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement (PPA) a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend'sBend’s nuclear and environmental liabilities that is identical to the share of the plant'splant’s output purchased by Entergy Texas under the PPA. Entergy Gulf States Louisiana will purchasepurchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas will purchasepurchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The PPAs associated with the gas-fired generating plants will terminate when retail open access commences in Entergy Texas' jurisdiction or when the unit(s) is no longer dispatched by theis/are removed from Entergy System. If Entergy Texas implements retail open access, it will terminate its participation in the System Agreement, except for the portion of the System Agreement related to transmission equalization.dispatch. The dispatch and operation of the generating plants willdid not change as a result of the jurisdictional separation. The LPSC staff has asserted that the PPAs would terminate if Entergy Texas and Entergy Gulf States Louisiana join MISO. Entergy Gulf States Louisiana filed testimony opposing that position. The LPSC has stayed consideration of this issue until December 31, 2013.
The jurisdictional separation occurred through completion of the following steps:
· | Through a Texas statutory merger-by-division, Entergy Gulf States, Inc. was renamed as Entergy Gulf States Louisiana, Inc., a Texas corporation, and the new Texas business corporation Entergy Texas, Inc. was formed. |
· | Entergy Gulf States, Inc. allocated the assets described above to Entergy Texas, and all of the capital stock of Entergy Texas was issued directly to Entergy Gulf States, Inc.'s parent company, Entergy Corporation. |
· | Entergy Corporation formed EGS Holdings, Inc., a Texas corporation, and contributed all of the common stock of Entergy Gulf States Louisiana, Inc. to EGS Holdings, Inc. |
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· | EGS Holdings, Inc. formed the Louisiana limited liability company Entergy Gulf States Louisiana, L.L.C. and then owned all of the issued and outstanding membership interests of Entergy Gulf States Louisiana, L.L.C. |
· | Entergy Gulf States Louisiana, Inc. then merged into Entergy Gulf States Louisiana, L.L.C., with Entergy Gulf States Louisiana, L.L.C. being the surviving entity. |
· | Entergy Corporation now owns EGS Holdings, Inc. and Entergy Texas in their entirety, and EGS Holdings, Inc. now owns Entergy Gulf States Louisiana's common membership interests in their entirety. |
Entergy Louisiana Corporate Restructuring
Effective December 31, 2005, Entergy Louisiana, LLC, a limited liability company organized under the laws of the State of Texas, as part of a restructuring involving a Texas statutory merger-by-division succeeded to all of the regulated utility operations of Entergy Louisiana, Inc. Entergy Louisiana, LLC was allocated substantially all of the property and other assets of Entergy Louisiana, Inc., including all assets used to provide retail and wholesale electric service to Entergy Louisiana, Inc.'s customers. Entergy Louisiana, LLC also assumed substantially all of the liabilities of Entergy Louisiana, Inc., including all of its debt securities and leases but excluding the outstanding preferred stock of Entergy Louisiana, Inc.
As the operator of Entergy Louisiana, Inc.'s retail utility operations, Entergy Louisiana, LLC is subject to the jurisdiction of the LPSC over electric service, rates and charges to the same extent that the LPSC possessed jurisdiction over Entergy Louisiana, Inc.'s retail utility operations. The restructuring implemented a recommendation from the LPSC staff, intended to reduce corporate franchise taxes, and is expected to result in a decrease in that component of Entergy Louisiana, LLC's rates to its Louisiana retail customers.
On December 31, 2005, and immediately prior to the formation of Entergy Louisiana, LLC, Entergy Louisiana, Inc. changed its state of incorporation from Louisiana to Texas and its name to Entergy Louisiana Holdings, Inc. Upon the effectiveness of the statutory merger-by-division on December 31, 2005, Entergy Louisiana, LLC was organized and Entergy Louisiana Holdings held all of Entergy Louisiana, LLC's common membership interests. All of the common membership interests of Entergy Louisiana, LLC continue to be held by Entergy Louisiana Holdings and all of the common stock of Entergy Louisiana Holdings continues to be held by Entergy Corporation. As part of the merger-by-division, Entergy Louisiana Holdings succeeded to Entergy Louisiana, Inc.'s rights and obligations with respect to Entergy Louisiana, Inc.'s outstanding preferred stock, which had an aggregate par value of approximately $100 million. In June 2006, Entergy Louisiana Holdings redeemed all of its preferred stock and amended its charter to eliminate authority to issue any future series of preferred stock.
Although Entergy Louisiana, LLC has been consolidated for financial reporting purposes since its inception, it did not join in the filing of Entergy's consolidated federal income tax return through the tax year 2007. Entergy Louisiana, LLC filed separate federal income tax returns, paid federal income taxes on a stand-alone basis, and was not a party to the Entergy System's intercompany tax allocation agreement through 2007. As such, Entergy Louisiana, LLC may have made elections for tax purposes that may differ from those made by the Entergy consolidated tax group, which may result in Entergy Louisiana, LLC having more exposure to tax liability than it would have had, had it been included in the Entergy consolidated tax return. Beginning in 2008, Entergy Louisiana, LLC joined the consolidated federal income tax return and participated in the Entergy System's intercompany tax allocation agreement. Entergy Louisiana Holdings will continue as a party to the Entergy System's intercompany tax allocation agreement.
After the merger-by-division, Entergy Louisiana, LLC issued $100 million of its preferred membership interests, which grant the holders thereof the power to vote together, as a single class, with Entergy Corporation as the holder of the common membership interests. The preferred membership interests have approximately 23% of the total voting power. Because Entergy Corporation, indirectly through Entergy Louisiana Holdings, owns all of the common membership interests in Entergy Louisiana, LLC, Entergy Corporation will be able to elect the entire board of directors of Entergy Louisiana, LLC, except in certain circumstances if distributions on Entergy Louisiana, LLC's preferred membership interests are in arrears.
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Earnings Ratios of Registrant Subsidiaries
The Registrant Subsidiaries'Subsidiaries’ ratios of earnings to fixed charges and ratios of earnings to combined fixed charges and preferred dividends or distributions pursuant to Item 503 of SEC Regulation S-K are as follows:
| | | Ratios of Earnings to Fixed Charges Years Ended December 31, | | Ratios of Earnings to Fixed Charges Years Ended December 31, |
| | | 2009 | | 2008 | | 2007 | | 2006 | | 2005 | | 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | 2.39 | | 2.33 | | 3.19 | | 3.37 | | 3.75 | | 3.79 | | 4.31 | | 3.91 | | 2.39 | | 2.33 |
| Entergy Gulf States Louisiana | | 2.99 | | 2.44 | | 2.84 | | 3.01 | | 3.34 | | 3.48 | | 4.36 | | 3.58 | | 2.99 | | 2.44 |
| Entergy Louisiana | | 3.52 | | 3.14 | | 3.44 | | 3.23 | | 3.50 | | 2.08 | | 1.86 | | 3.41 | | 3.52 | | 3.14 |
| Entergy Mississippi | | 3.25 | | 2.92 | | 3.22 | | 2.54 | | 3.16 | | 2.79 | | 3.55 | | 3.35 | | 3.31 | | 2.92 |
| Entergy New Orleans | | 3.66 | | 3.71 | | 2.74 | | 1.52 | | 1.22 | | 3.02 | | 5.37 | | 4.43 | | 3.61 | | 3.71 |
| Entergy Texas | | 1.92 | | 2.04 | | 2.07 | | 2.12 | | 2.06 | | 1.76 | | 2.34 | | 2.10 | | 1.92 | | 2.04 |
| System Energy | | 3.73 | | 3.29 | | 3.95 | | 4.05 | | 3.85 | | 5.12 | | 3.85 | | 3.64 | | 3.73 | | 3.29 |
| | | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| | | 2009 | | 2008 | | 2007 | | 2006 | | 2005 |
| | | | | | | | | | | |
| Entergy Arkansas | | 2.09 | | 1.95 | | 2.88 | | 3.06 | | 3.34 |
| Entergy Gulf States Louisiana | | 2.95 | | 2.42 | | 2.73 | | 2.90 | | 3.18 |
| Entergy Louisiana | | 3.27 | | 2.87 | | 3.08 | | 2.90 | | 3.50 |
| Entergy Mississippi | | 3.01 | | 2.67 | | 2.97 | | 2.34 | | 2.83 |
| Entergy New Orleans | | 3.38 | | 3.45 | | 2.54 | | 1.35 | | 1.12 |
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| | | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| | | 2012 | | 2011 | | 2010 | | 2009 | | 2008 |
| | | | | | | | | | | |
| Entergy Arkansas | | 3.36 | | 3.83 | | 3.60 | | 2.09 | | 1.95 |
| Entergy Gulf States Louisiana | | 3.43 | | 4.30 | | 3.54 | | 2.95 | | 2.42 |
| Entergy Louisiana | | 1.93 | | 1.70 | | 3.19 | | 3.27 | | 2.87 |
| Entergy Mississippi | | 2.59 | | 3.27 | | 3.16 | | 3.06 | | 2.67 |
| Entergy New Orleans | | 2.67 | | 4.74 | | 4.08 | | 3.33 | | 3.45 |
The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.
Entergy's Non-Utility Nuclear business ownsDuring 2010 Entergy integrated its non-utility nuclear and operatesits non-nuclear wholesale assets businesses into a new organization called Entergy Wholesale Commodities.
Entergy Wholesale Commodities includes the ownership and operation of six nuclear power plants, five of which are located in the Northeast United States, with the sixth located in Michigan, and is primarily focused on selling electric power produced by those plants to wholesale customers. Non-Utility Nuclear'sEntergy Wholesale Commodities’ revenues are primarily derived from sales of energy and sales of generation capacity. This businesscapacity from these plants. Entergy Wholesale Commodities also provides operations and management services, including decommissioning services, to nuclear power plants owned by other utilities in the United States. Operations
Entergy Wholesale Commodities also includes the ownership of, or participation in joint ventures that own, non-nuclear power plants and management services, including decommissioning services, are provided through Entergy's wholly-owned subsidiary, Entergy Nuclear, Inc.the sale to wholesale customers of the electric power produced by these plants.
Property
Nuclear Generating Stations
Entergy's Non-Utility Nuclear business ownsEntergy Wholesale Commodities includes the ownership of the following nuclear power plants:
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Reactor Type | | License Expiration Date | | Net Book Value (in millions) | | Market | | In Service Year | | Acquired | | Location | | Capacity- Reactor Type | | License Expiration Date |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Pilgrim | | IS0-NE | | 1972 | | July 1999 | | Plymouth, MA | | Boiling Water | | 2012 | | $253 | | IS0-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 |
| FitzPatrick | | NYISO | | 1975 | | Nov. 2000 | | Oswego, NY | | Boiling Water | | 2034 | | $417 | | NYISO | | 1975 | | Nov. 2000 | | Oswego, NY | | 838 MW - Boiling Water | | 2034 |
| Indian Point 3 | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | Pressurized Water | | 2015 | | $626 | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 |
| Indian Point 2 | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | Pressurized Water | | 2013 | | $952 | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 |
| Vermont Yankee | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | Boiling Water | | 2012 | | $333 | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 |
| Palisades | | MISO | | 1971 | | Apr. 2007 | | South Haven, MI | | Pressurized Water | | 2031 | | $737 | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 |
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Non-Utility NuclearWholesale Commodities also ownsincludes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New
York that were acquired when Non-Utility NuclearEntergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.
TheIn March 2011 and May 2012 the NRC renewed the operating licenses forof Vermont Yankee and Pilgrim, respectively, for an additional 20 years, as a result of which each license now expires in 2032. For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements. In the Vermont Yankee license renewal case, the Vermont Department of Public Service and the New England Coalition appealed the NRC’s renewal of Vermont Yankee’s license to the D.C. Circuit. In June 2012 the D.C. Circuit denied that appeal. The time for seeking further judicial review of the NRC’s issuance of Vermont Yankee’s renewed operating license has expired. In the Pilgrim license renewal
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case, three contentions remained pending before the ASLB at the time the license was issued. Two of those contentions were subsequently denied by the ASLB and not appealed within the applicable time. A third remaining contention (alleging failure of the Pilgrim Environmental Impact Statement to address adequately an endangered species) was denied by the ASLB and then appealed to the NRC, which denied the appeal on December 6, 2012. No appeal of the NRC’s decision was filed within the time allowed for such appeals. The NRC has indicated that should the appeal of a contention result in voiding of the renewed license, Pilgrim could operate under the “timely renewal” doctrine in reliance on the prior, and now superseded, license until proceedings concerning the renewed license are final. Massachusetts appealed the NRC’s renewal of Pilgrim’s license to the United States Court of Appeals for the First Circuit. Entergy intervened in that appeal. Briefing was completed and oral argument was held December 5, 2012. On February 25, 2013, the United States Court of Appeals for the First Circuit denied Massachusetts’s appeal.
The NRC operating licenses for Indian Point 2 and Indian Point 3 expire in 2012September 2013 and December 2015, respectively, and NRC license renewal applications are in process for these plants. Under federal law, nuclear power plants may continue to 2015. Licenseoperate beyond their license expiration dates while their renewal applications are pending at the NRC for these four plants, and are the subject of public and local political debate as well as state permitting requirements.approval. Various parties have expressed opposition to the pending license renewal applications. There is an ongoing proceeding before the Atomic Safety and Licensing Board (ASLB) of the NRC and contentions have been admitted for litigation regarding the Indian Point License renewals. The ASLB has completed its proceedings regarding Vermont Yankee, but the New England Coalition filed a petition for NRC review of the ASLB's decision on July 23, 2009. Also, the ASLB has completed its proceedings regarding Pilgrim, but Pilgrim Watch filed a petition for NRC review of the ASLB's decision on November 12, 2008. Both the Vermont Yankee and Pilgrim license renewals are awaiting an NRC decision on the petitions for review. On September 8, 2008, the NRC granted Entergy's request for a renewed operating license for the FitzPatrick nuclear plant, which extends the operating license term for that plant by twenty years, to October 17, 2034.
In addition, for Vermont Yankee the state certificates of public good to operate the plant and store spent nuclear fuel also expire in 2012. Non-Utility Nuclear filed an application with the Vermont Public Service Board on March 3, 2008 for approval of continued operations and storage of spent nuclear fuel generated after March 21, 2012. Under Vermont law the Vermont General Assembly approval of Non-Utility Nuclear's request is required for the request to be granted. During its 2009 session, which concluded in May, several committees of the Vermont General Assembly held hearings on Vermont Yankee, but no bill or resolution was introduced for approval of continued operation and storage of spent nuclear fuel generated after March 21, 2012. Entergy had anticipated that the Vermont General Assembly might consider authorizing continued operation of Vermont Yankee and spent fuel storage during its 2010 session, which began in January. Governor Jim Douglas, however, issued a statement on January 27, 2010 indicating he would not ask the Vermont General Assembly to consider Vermont Yankee license renewal during its 2010 session pending an ongoing investigation relating to elevated levels of tritium found in Vermont Yankee groundwater monitoring wells. The Governor's statement also expressed concerns about potential decommissioning costs and about inconsistent information related to underground piping at Vermont Yankee carrying radionuclides that was provided by Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations, Inc. in a proceeding before the Vermont Public Service Board related to extending operation of Vermont Yankee beyond its current operating license. Notwithstanding the Governor’s position, on February 24, 2010, a bill to approve the continued operation of Vermont Yankee was advanced to a vote by the Vermont Senate leadership and defeated by a margin of 26 to 4. This vote does not preclude the Vermont Senate from voting again on a similar bill in the future. Vermont is the only state of which Entergy is aware the state legislature has asserted that it has the authority to approve the continued operation of a Non-Utility Nuclear plant for a renewed license term.
licenses. In April 2007, Non-Utility NuclearEntergy submitted anthe application to the NRC to renew the operating licenses for Indian Point 2 and 3 for an additional 20 years. The ASLB has admitted 21 contentions raised by the State of New York or other parties, which were combined into 16 discrete issues. Three of the issues have been resolved, and 13 issues remain subject to ASLB resolution. In July 2011 the ASLB granted the State of New York’s motion for summary disposition of an admitted contention challenging the adequacy of a section of Indian Point’s environmental analysis as incorporated in the Final Supplemental Environmental Impact Statement (FSEIS) (discussed below). That section provided cost estimates for Severe Accident Mitigation Alternatives (SAMAs), which are hardware and procedural changes that could be implemented to mitigate estimated impacts of off-site radiological releases in case of a hypothesized severe accident. In addition to finding that the SAMA cost analysis was insufficient, the ASLB directed the NRC Staffstaff to explain why cost-beneficial SAMAs should not be required to be implemented. Entergy appealed the ASLB’s decision to the NRC and the NRC staff supported Entergy’s appeal, while the State of New York opposed it. In December 2011 the NRC denied Entergy’s appeal as premature, stating that the appeal could be renewed at the conclusion of the ASLB proceedings.
Pursuant to ASLB scheduling orders in the Indian Point 2 and 3 license renewal proceeding, hearings on the nine contentions remaining in “Track 1” were held over 12 days in October, November, and December 2012. Testimony on the four contentions currently in “Track 2” has not been completed. Track 2 hearings have not been scheduled.
The NRC staff is performingalso continuing to perform its technical and environmental reviews of the Indian Point 2 and 3 license renewal application. ItThe NRC staff issued a Final Safety Evaluation Report (FSER) in August 2009, a supplement to the FSER in August 2011, a FSEIS in December 2010 and a supplement to the FSEIS in June 2012. The NRC staff issued a draft supplemental FSEIS in June 2012 and has stated its intent to issue, following an opportunity for comment, another supplement to the FSEIS by April 30, 2013. In addition, the NRC staff has stated its intent to issue a further supplement to the FSER by July 31, 2013. These reports are expected to affect testimony yet to be filed on Track 2 contentions.
The hearing process is an integral component of the NRC’s regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Entergy is participating fully in the hearing process as permitted by the NRC’s hearing rules. As noted in Entergy’s responses to the various intervenor filings, Entergy believes the contentions proposed by the intervenors are unsupported and without merit. Entergy will continue to work with the NRC staff as it completes its technical and environmental impact statement in December 2008, a safety evaluation with open items in January 2009,reviews of the Indian Point 2 and a final safety evaluation report in August 2009. 3 license renewal applications.
The New York State Department of Environmental Conservation has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. For additional discussion of the Indian Point alsoClean Water Act Section 401 water quality certification see “Environmental Regulation -Clean Water Act,” below. In addition, the consistency of Indian Point’s operations with New York State’s coastal management policies must obtain abe resolved to the extent required by the Coastal Zone Management Act consistency determination from the New York Department of State prior(CZMA). On July 24, 2012, Entergy filed a supplement to getting its renewed license. For a discussion concerning the status of Non-Utility Nuclear’s efforts to obtain these certifications and determinations, see "Environmental Regulation, Clean Water Act" below.
The NRC is required by statute to provide an opportunity to members of the public to request a hearing on the Indian Point 2 and 3 license renewal application. In early December 2007,application currently pending before the NRC. The supplement states that, based on applicable federal law and in light of prior reviews by the State of New York, the NRC received thirteen petitions to intervene inmay issue the license renewal proceedingrequested renewed operating licenses for Indian Point 2 and 3. The petitions were filedwithout the need for an additional consistency review by various state and local government entities, including the StatesState of New York and Connecticut, as well as several public interest groups. The ASLB summarily rejected four ofunder the thirteen petitions toCZMA. On July 30, 2012,
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interveneEntergy filed a motion for declaratory order with the ASLB seeking confirmation of its position that no further CZMA consistency determination is required before the NRC may issue renewed licenses. Responses to Entergy’s motion for declaratory order are due March 22, 2013. In addition, Entergy filed with the New York State Department of State (NYSDOS) on November 7, 2012 a petition for declaratory order that Indian Point is grandfathered under either of two criteria prescribed by the New York Coastal Management Program (NYCMP), which sets forth the state coastal policies applied in a CZMA consistency review. The NYSDOS denied the motion by order dated January 9, 2013. An appeal may be taken to state court within four months. Finally, on December 2007. The nine remaining petitions contained over 160 proposed contentions, which are issues17, 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMP policies. Entergy included in the consistency determination a “reservation of law or fact pertainingrights” clarifying that Entergy does not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. On January 16, 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it does not include the further supplement to the license renewal applicationFSEIS that, as indicated above, is targeted for issuance by April 30, 2013. The six-month federal deadline for state decision on a consistency determination does not begin to run until the petitioners seek to have adjudicated bysubmission is complete.
Non-nuclear Generating Stations
Entergy Wholesale Commodities includes the NRC.ownership, or interests in joint ventures that own, the following non-nuclear power plants:
Plant | | Location | | Ownership | | Net Owned Capacity(1) | | Type |
| | | | | | | | |
| Rhode Island State Energy Center; 583 MW | | Johnston, RI | | 100% | | 583 MW | | Gas |
| Ritchie Unit 2; 544 MW | | Helena, AR | | 100% | | 544 MW | | Gas/Oil |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(2) | | Coal |
| Top of Iowa; 80 MW (3) | | Worth County, IA | | 50% | | 40 MW | | Wind |
| White Deer; 80 MW (3) | | Amarillo, TX | | 50% | | 40 MW | | Wind |
| RS Cogen; 425 MW (3) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(2) | | Coal |
| (1) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
| (2) | The owned MW capacity is the portion of the plant capacity owned by Entergy Wholesale Commodities. For a complete listing of Entergy’s jointly-owned generating stations, refer to “Jointly-Owned Generating Stations” in Note 1 to the financial statements. |
| (3) | Indirectly owned through interests in unconsolidated joint ventures. |
In January 2008, in accordance with the NRC's hearing rules, Non-Utility Nuclear filed nine detailed answers to the petitions, opposing allfourth quarter 2010, Entergy sold its 61 percent share of the petitioners' proposed contentions. The NRC Staff, which functions as an independent party in any hearing, also filed detailed responses to the petitions. The NRC Staff opposed admission of all but a few of the petitioners' proposed contentions. On July 31, 2008, the ASLB granted, in part, the petitions to intervene of the State of New York, Riverkeeper, Inc., and Hudson River Sloop Clearwater, Inc., admitting a total of 17 technical and environmental contentions for adjudication. Due to similarities among certain contentions, the Board consolidated the 17 admitted contentions into 13 discrete issues. The ASLB subsequently permitted the Town of Cortlandt, Village of Buchanan, City of New York, State of Connecticut, and WestchesterHarrison County to participate in the proceeding as "interested" governmental entities, as allowed by the NRC regulations. The ASLB issued its initial case management and scheduling order during the first quarter 2009, although the parties began the discovery process pursuant to an ASLB order issued in December 2008 and an agreement reached by the parties in January 2009 regarding disclosure issues. Any evidentiary hearings on the admitted contentions are expected to occur in 2010.550 MW combined cycle gas-fired power plant.
The hearing process is an integral component of the NRC's regulatory framework, and evidentiary hearings on license renewal applications are not uncommon. Non-Utility Nuclear intends to participate fully in the hearing process as permitted by the NRC's hearing rules. As noted in Non-Utility Nuclear's responses to the various petitions to intervene, Non-Utility Nuclear believes that many of the issues raised by the petitioners are unsupported and without merit. Furthermore, Non-Utility Nuclear believes that it will carry its burden of proof with respect to any issues that were admitted for evidentiary hearings. Non-Utility Nuclear will continue to work with the NRC Staff as it completes its technical and environmental reviews of the license renewal application, and based on current scheduling expects to obtain 20-year license renewals for Indian Point 2 and Indian Point 3 in 2011.
InterconnectionsIndependent System Operators
The Pilgrim and Vermont Yankee and Rhode Island plants fall under the authority of the Independent System Operator (ISO) New England and the FitzPatrick and Indian Point plants fall under the authority of the New York Independent System Operator (NYISO). The Palisades plant falls under the authority of the Midwest Independent System Operator (MidwestISO).MISO. The primary purpose of ISO New England, NYISO, and MidwestISOMISO is to direct the operations of the major generation and transmission facilities in their respective regionsregions; ensure grid reliability; administer and in doing so also takes responsibility for ensuring grid reliability, administering and monitoringmonitor wholesale electricity marketsmarkets; and planningplan for their respective region’s energy needs.
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Energy and Capacity Sales
As a wholesale generator, Entergy's Non-Utility Nuclear business'sEntergy Wholesale Commodities core business is selling energy, measured in MWh, to its customers. Non-Utility NuclearEntergy Wholesale Commodities enters into forward contracts with its customers and sells energy in the day ahead or spot markets. In addition to selling the energy produced by its plants, Non-Utility NuclearEntergy Wholesale Commodities sells unforced capacity, towhich allows load-serving entities which allows those companies to meet specified reserve and related requirements placed on them by the ISOs in their respective areas. Non-Utility Nuclear'sEntergy Wholesale Commodities’ forward fixed price power contracts consist of contracts to sell energy only, contracts to sell capacity only, and bundled contracts in which it sells both capacity and energy. While the terminology and payment mechanics vary in these contracts, each of these types of contracts requires Non-Utility NuclearEntergy Wholesale Commodities to deliver MWh of energy, to its counterparties, make capacity available, to them, or both. See "“Commodity PriceMarket and Credit Risk Sensitive Instruments - - Power Generation"” in Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for additional information regarding these contracts.
In addition to the contracts discussed in "“Commodity PriceMarket and Credit Risk Sensitive Instruments - - Power Generation," Non-Utility Nuclear's,” Entergy’s purchase of the Vermont Yankee plant included a value sharing agreement providing for payments to the seller in the event that the plant'splant operates beyond March 2012 pursuant to a renewed NRC operating license term is renewed beyond its original expiration in 2012.license. Under the value sharing agreement, to the extent that the average annual price of the energy sales from the plant exceeds the specified strike price, initially $61/MWh and then adjusted annually based on three indices, the Non-Utility Nuclear businessVermont Yankee will pay 50% of the amount exceeding the strike prices to the seller. These payments, if required, will be recorded as adjustments to the purchase price of the plants. The value sharing would begin in 2012 and extend into 2022.
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As part of the purchase of the Palisades plant, Entergy's Non-Utility Nuclear businessEntergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant'splant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy will receive the value of any new environmental credits for the first ten years of the agreement. EntergyPalisades and Consumers Energy will share on a 50/50 basis the value of any new environmental credits for years 11 through 15 of the agreement. The environmental credits are defined as benefits from a change in law that causes capability of the plant as of the purchase date to become a tradable attribute (e.g., emission credit, renewable energy credit, environmental credit, "green"“green” credit, etc.) or otherwise to have a market value.
Customers
Non-Utility Nuclear'sEntergy Wholesale Commodities’ customers for the sale of both energy and capacity from its nuclear plants include retail power providers, utilities, electric power co-operatives, power trading organizations and other power generation companies. These customers include Consolidated Edison, NYPA, and Consumers Energy, companies from which Non-Utility NuclearEntergy purchased plants, and ISO New England, NYISO, and NYISO. AsMISO. Substantially all of December 31, 2009,the counterparties or their guarantors for the planned energy output under contract for Non-Utility Nuclear through 2014, 99.7% of the planned energy output is under contract with counterparties withEntergy Wholesale Commodities nuclear plants have public investment grade credit ratings and 0.3% is withor are load-serving entities without public credit ratings.
Competition
The ISO New England and NYISO markets are highly competitive. Non-Utility NuclearEntergy Wholesale Commodities has approximately 85numerous competitors in New England and 70 competitors in New York, including generation companies affiliated with regulated utilities, other independent power producers, municipal and co-operative generators, owners of co-generation plants and wholesale power marketers. Non-Utility NuclearEntergy Wholesale Commodities is an independent power producer, which means it generates power for sale to third parties at day ahead or spot market prices to the extent that the power is not sold under a fixed price contract. Municipal and co-operative generators also generate power but use most of it to deliver power to their municipal or co-operative power customers. Owners of co-generation plants produce power primarily for their own consumption. Wholesale power marketers do not own generation; rather they buy power from generators or other market participants and resell it to retail providers or other market participants. Competition in the New England and New York power markets is affected by, among other factors, the amount of generation and transmission capacity in these markets. Based on the latest available information, Non-Utility Nuclear's plants provided approximately 7% of the aggregate net generation capacity serving the New England power market and 16% of the aggregate net generation capacity serving the New York power market. The MidwestISO market includes approximately 280 participants. The MidwestISOMISO does not have a formal, centralized forward capacity market, but load serving entities do transact capacity through bilateral contracts. Palisades'Palisades’s current output is fully contracted to Consumers Energy through 2022 and, therefore, Non-Utility NuclearEntergy Wholesale Commodities does not expect to be materially affected by competition in the MidwestISOMISO market in the near term.
Seasonality
Non-Utility Nuclear's revenues and operating income are subject to mild fluctuations during the year due to seasonal factors and weather conditions. When outdoor and cooling water temperatures are lower, generally during colder months, Non-Utility Nuclear's nuclear power plants operate more efficiently, and consequently, it generates more electricity and records higher revenues and operating income. Although some of its annual contracts provide for monthly pricing, Non-Utility Nuclear derives the majority of its revenues from fixed price forward power sales that are generally sold at a single price for a calendar year, which can offset the effects of seasonality and weather conditions on monthly power prices.
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Entergy Wholesale Commodities’ revenues and operating income are subject to fluctuations during the year due to seasonal factors, weather conditions, and contract pricing. Refueling outages are generally scheduled for the spring and the fall, and cause volumetric decreases during those seasons. When outdoor and cooling water temperatures are lower, generally during colder months, Entergy Wholesale Commodities’ nuclear power plants operate more efficiently, and consequently, generate more electricity. Many of Entergy Wholesale Commodities’ contracts provide for shaped pricing over the course of the year. As a result of these factors, Entergy Wholesale Commodities’ revenues are typically higher in the first and third quarters than in the second and fourth quarters.
Fuel Supply
Nuclear Fuel
See "“Fuel Supply, Nuclear Fuel"” in the Utility portion of Part I, Item 1 for a discussion of the nuclear fuel cycle and markets. Entergy Nuclear Fuels Company, a wholly-owned subsidiary, is responsible for contracts to acquire nuclear materials, except for fuel fabrication, for Non-Utility Nuclear'sEntergy Wholesale Commodities’ nuclear power plants, while Entergy Nuclear Operations, Inc. acts as the agent for the purchase of nuclear fuel assembly fabrication services. All contracts for the disposal of spent nuclear fuel are between the DOE and each of the nuclear power plants.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Non-Utility Nuclear.Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Non-Utility NuclearEntergy Wholesale Commodities subsidiaries that own that business'snuclear power plants (generating subsidiaries). As part of a series of agreements, ENPM agreed to assume and/or otherwise service the existing power purchase agreements that were in effect between the generating subsidiaries and their customers. ENPM functions include origination of new energy and capacity transactions, generation scheduling, contract management (including billing and settlements), and market and credit risk mitigation.
Entergy Nuclear, Inc. pursues service agreements with other nuclear power plant owners who seek the advantages of Entergy'sEntergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Non-Utility NuclearEntergy Wholesale Commodities subsidiaries include engineering, operations and maintenance, fuel procurement, management and supervision, technical support and training, administrative support, and other managerial or technical services required to operate, maintain, and decommission nuclear electric power facilities. Entergy Nuclear, Inc. provided decommissioning services for the Maine Yankee nuclear power plant and continues to pursue opportunities for Non-Utility NuclearEntergy Wholesale Commodities with other nuclear plant owners through operating agreements or innovative arrangements such as structured leases.agreements.
In September 2003, Entergy's Non-Utility Nuclear business agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The contract is for 10 years, the remaining term of the plant's current operating license. Entergy will receive $14 million in each of the remaining years of the contract. Entergy can also receive up to $6 million more per year if safety and regulatory goals are met. In addition, Entergy will be reimbursed for all employee-related expenses. In 2006, Entergy Nuclear, Inc. signed an agreement to provide license renewal services for the Cooper Nuclear Station. Entergy Nuclear, Inc. has now signed an agreement with Nebraska Public Power District to extend management support services to Cooper Nuclear Station until January 2029. The plant’s original operating license, currently due to expire in 2014, is currently under review by the NRC for a 20-year license renewal.
Entergy Nuclear, Inc.also offers operating license renewal and life extension services to nuclear power plantsplant owners. TLG Services, a subsidiary of Entergy Nuclear Inc., through its subsidiary, TLG Services, offers decommissioning, engineering, and related services to nuclear power plant owners. In April 2009, Non-Utility NuclearEntergy announced that it will team with energy firm ENERCON to offer nuclear development services ranging from plant relicensing to full-service, new plant deployment. ENERCON has experience in engineering, environmental, technical and management services.
Non-Nuclear Wholesale Assets BusinessIn September 2003, Entergy agreed to provide plant operation support services for the 800 MW Cooper Nuclear Station located near Brownville, Nebraska. The original contract was to expire in 2014 corresponding to the original operating license life of the plant. In 2006 an Entergy subsidiary signed an agreement to provide license renewal services for the Cooper Nuclear Station. The Cooper Nuclear Station received its license renewal from the NRC on November 29, 2010. Entergy continues to provide implementation services for the renewed license. In 2010 an Entergy subsidiary signed an agreement to extend the management support services to Cooper Nuclear Station by 15 years, through January 2029.
The non-nuclear wholesale assets business sells to wholesale customers the electric power produced by power plants that it owns while it focuses on improving performance and exploring sales or restructuring opportunities for its power plants. Such opportunities are evaluated consistent with Entergy's market-based point-of-view.
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Property
Generating Stations
The capacity of the generating stations owned in Entergy's non-nuclear wholesale assets business as of December 31, 2009 is indicated below:
Plant
| | Location
| | Ownership
| | Net Owned
Capacity(1)
| | Type
|
| | | | | | | | |
Ritchie Unit 2, 544 MW | | Helena, AR | | 100% | | 544 MW | | Gas/Oil |
Independence Unit 2, 842 MW (2) | | Newark, AR | | 14% | | 121 MW(3) | | Coal |
Top of Iowa, 80 MW (4) | | Worth County, IA | | 50% | | 40 MW | | Wind |
White Deer, 80 MW (4) | | Amarillo, TX | | 50% | | 40 MW | | Wind |
RS Cogen, 425 MW (4) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
Harrison County, 550 MW | | Marshall, TX | | 61% | | 335 MW(3) | | Combined Cycle Gas Turbine |
(1) | "Net Owned Capacity" refers to the nameplate rating on the generating unit. |
(2) | Entergy Louisiana and Entergy New Orleans currently purchase 101 MW of capacity and energy from Independence Unit 2. The transaction included an option for Entergy Louisiana and Entergy New Orleans to acquire an ownership interest in the unit for a total price of $80 million, subject to various adjustments. On March 5, 2008, Entergy Louisiana and Entergy New Orleans provided notice of their intent to exercise the option. The parties are negotiating the terms and conditions of the ownership acquisition. |
(3) | The owned MW capacity is the portion of the plant capacity owned by Entergy's non-nuclear wholesale assets business. For a complete listing of Entergy's jointly-owned generating stations, refer to "Jointly-Owned Generating Stations" in Note 1 to the financial statements.
|
(4) | Indirectly owned through interests in unconsolidated joint ventures. |
In addition to these generating stations, Entergy's non-nuclear wholesale assets business has a contract to take 60 MW of the power from a portion of the Nelson 6 coal plant owned by a third party.
Entergy-Koch
Entergy-Koch is a joint venture owned 50% each by Entergy and Koch Industries, Inc, through subsidiaries. Entergy-Koch began operations on February 1, 2001. Entergy contributed most of the assets and trading contracts of its power marketing and trading business and $414 million cash to the venture and Koch contributed its approximately 8,000-mile Koch Gateway Pipeline (renamed Gulf South Pipeline), gas storage facilities, and Koch Energy Trading, which marketed and traded electricity, gas, weather derivatives, and other energy-related commodities and services. As specified in the partnership agreement, Entergy contributed an additional $72.7 million to the partnership in January 2004.
In the fourth quarter of 2004, Entergy-Koch sold its energy trading and pipeline businesses to third parties. The sales came after a review of strategic alternatives for enhancing the value of Entergy-Koch, LP. Entergy received $862 million of cash distributions in 2004 from Entergy-Koch after the business sales. Due to the November 2006 expiration of contingencies on the sale of Entergy-Koch's trading business, and the corresponding release to Entergy-Koch of sales proceeds held in escrow, Entergy received additional cash distributions of approximately $163 million during the fourth quarter of 2006 and recorded a gain of approximately $55 million (net-of-tax). In December 2009, Entergy reorganized its investment in Entergy-Koch, received a $25.6 million cash distribution, and received a distribution of certain software owned by the joint venture. Entergy-Koch is no longer an operating entity.
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Energy Policy Act of 2005
The Energy Policy Act of 2005 became law in August 2005. The legislation contains electricity provisions that, among other things:
· | Repealed PUHCA 1935, through enactment of PUHCA 2005, effective February 8, 2006; PUHCA 2005 and/or related amendments to Section 203(a) of the Federal Power Act (a) remove various limitations on Entergy Corporation as a registered holding company under PUHCA 1935; (b) require the maintenance and retention of books and records by certain holding company system companies for inspection by the FERC and state commissions, as appropriate; and (c) effectively leave to the jurisdiction of the FERC (or state or local regulatory bodies, as appropriate) (i) the issuance by an electric utility of securities; (ii) (A) the disposition of jurisdictional FERC electric facilities by an electric utility; (B) the acquisition by an electric utility of securities of an electric utility; (C) the acquisition by an electric utility of electric generating facilities (in each of the cases in (A), (B) and (C) only in transactions in excess of $10 million); (iv) electric public utility mergers; and (v) the acquisition by an electric public utility holding company of securities of an electric public utility company or its holding company in excess of $10 million or the merger of electric public utility holding company systems. PUHCA 2005 and the related FERC rule-making also provide a savings provision which permits continued reliance on certain PUHCA 1935 rules and orders after the repeal of PUHCA 1935. |
· | Codifies the concept of participant funding or cost causation, a form of cost allocation for transmission interconnections and upgrades, and allows the FERC to apply participant funding in all regions of the country. Participant funding helps ensure that a utility's native load customers only bear the costs that are necessary to provide reliable transmission service to them and not bear costs imposed by generators (the participants) who seek to deliver power to other regions. |
· | Provides financing benefits, including loan guarantees and production tax credits, for new nuclear plant construction, and reauthorizes the Price-Anderson Act, the law that provides an umbrella of insurance protection for the payment of public liability claims in the event of a major nuclear power plant incident. |
· | Revises current tax law treatment of nuclear decommissioning trust funds by allowing regulated and non-regulated taxpayers to make deductible contributions to fund the entire amount of estimated future decommissioning costs. |
· | Provides a more rapid tax depreciation schedule for transmission assets to encourage investment. |
· | Creates mandatory electricity reliability guidelines with enforceable penalties to help ensure that the nation's power transmission grid is kept in good repair and that disruptions in the electricity system are minimized. Entergy already voluntarily complies with National Electricity Reliability Council standards, which are similar to the guidelines mandated by the Energy Policy Act of 2005.
|
· | Establishes conditions for the elimination of the Public Utility Regulatory Policy Act's (PURPA) mandatory purchase obligation from qualifying facilities. |
· | Significantly increased the FERC's authorization to impose criminal and civil penalties for violations of the provisions of the Federal Power Act. |
Federal Power Act
The Federal Power Act regulates:provides the FERC the authority to regulate:
| · | the transmission and wholesale sale of electric energy in interstate commerce; |
| · | sales or acquisition of certain assets; |
| · | the licensing of certain hydroelectric projects; |
| · | certain other activities, including accounting policies and practices of electric and gas utilities; and |
| · | changes in control of FERC jurisdictional entities or rate schedules. |
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The Federal Power Act gives the FERC jurisdiction over the rates charged by System Energy for Grand Gulf capacity and energy provided to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans and over some of the rates charged by Entergy Arkansas and Entergy Gulf States Louisiana. The FERC also regulates the rates charged for intrasystem sales pursuant toprovisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants.
Entergy Arkansas holds a FERC license that expires in 2053 for two hydroelectric projects totaling 70 MW of capacity.
State Regulation
Utility
Entergy Arkansas is subject to regulation by the APSC, which includes the authority to:
| · | oversee utility service; |
| · | determine reasonable and adequate service; |
· | require proper accounting; |
| · | control the acquisition or sale of any public utility plant or property constituting an operating unit or system; |
| · | set rates of depreciation; |
| · | issue certificates of convenience and necessity and certificates of environmental compatibility and public need; and |
| · | regulate the issuance and sale of certain securities. |
ToAdditionally, Entergy Arkansas serves a limited number of retail customers in Tennessee and as a result, may be required to submit certain matters approved by the extent authorizedAPSC for consideration by governing legislation,the Tennessee Regulatory Authority. Additionally, Entergy TexasArkansas maintains limited facilities in Missouri but does not provide retail electric service to customers in Missouri. Although Entergy Arkansas obtained a certificate with respect to its Missouri facilities, Entergy Arkansas is not subject to the original jurisdiction of the municipal authorities of a number of incorporated citiesretail rate or regulatory scheme in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:
· | retail rates and service in unincorporated areas of its service territory; |
· | customer service standards; |
· | certification of new transmission lines; and |
· | extensions of service into new areas. |
Missouri.
Entergy Gulf States Louisiana'sLouisiana’s electric and gas business and Entergy Louisiana are subject to regulation by the LPSC as to:
| · | retail rates and charges; |
| · | certification of generating facilities; |
| · | certification of power or capacity purchase contracts; |
| · | audit of the fuel adjustment charge, environmental adjustment charge, and avoided cost payment to Qualifying Facilities; |
| · | integrated resource planning; |
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| · | utility mergers and acquisitions and other changes of control; and |
| · | depreciation accounting, and other matters. |
Entergy Louisiana is also subject to the jurisdiction of the City Council with respect to such matters within Algiers in Orleans Parish, although the precise scope of that jurisdiction differs from that of the LPSC.
Entergy Mississippi is subject to regulation by the MPSC as to the following:
| · | certification of generating facilities and certain transmission projects; |
| · | depreciation rates; and |
| · | retail rates.mergers and changes of control. |
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Entergy Mississippi is also subject to regulation by the APSC as to the certificate of environmental compatibility and public need for the Independence Station, which is located in Arkansas.
Entergy New Orleans is subject to regulation by the City Council as to the following:
| · | retail rates and charges; |
| · | depreciation, accounting, and |
| · | issuance and sale of certain securities; and |
To the extent authorized by governing legislation, Entergy Texas is subject to the original jurisdiction of the municipal authorities of a number of incorporated cities in Texas with appellate jurisdiction over such matters residing in the PUCT. Entergy Texas is also subject to regulation by the PUCT as to:
| · | retail rates and service in unincorporated areas of its service territory, and in municipalities that have ceded jurisdiction to the PUCT; |
| · | customer service standards; |
| · | certification of certain transmission projects; and |
| · | extensions of service into new areas. |
Regulation of the Nuclear Power Industry
Atomic Energy Act of 1954 and Energy Reorganization Act of 1974
Under the Atomic Energy Act of 1954 and the Energy Reorganization Act of 1974, the operation of nuclear plants is heavily regulated by the NRC, which has broad power to impose licensing and safety-related requirements. The NRC has broad authority to impose fines or shut down a unit, or both, depending upon its assessment of the severity of the situation, until compliance is achieved. Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy, as owners of all or portions of ANO, River Bend, Waterford 3, and Grand Gulf, respectively, and Entergy Operations, as the licensee and operator of these units, are subject to the jurisdiction of the NRC. Entergy's Non-Utility Nuclear business isEntergy subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC'sNRC’s jurisdiction as the ownerowners and operator of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures at Entergy'sEntergy’s nuclear plants because of revised safety requirements of the NRC could be required in the future.
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Nuclear Waste Policy Act of 1982
Spent Nuclear Fuel
Under the Nuclear Waste Policy Act of 1982, the DOE is required, for a specified fee, to construct storage facilities for, and to dispose of, all spent nuclear fuel and other high-level radioactive waste generated by domestic nuclear power reactors. Entergy'sEntergy’s nuclear owner/licensee subsidiaries provide for the estimated future disposal costs of spent nuclear fuel in accordance with the Nuclear Waste Policy Act of 1982. The affected Entergy companies entered into contracts with the DOE, whereby the DOE is to furnish disposal services at a cost of one mill per net kWh generated and sold after April 7, 1983, plus a one-time fee for generation prior to that date. Entergy Arkansas is the only one of the Utility operating companies that generated electric power with nuclear fuel prior to that date and has a recorded liability as of December 31, 20092012 of $180.7$181.2 million for the one-time fee. Entergy's Non-Utility Nuclear business hasEntergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and 2, Vermont Yankee, Palisades, and Palisades/Big Rock Point spent fuel disposal contracts with the DOE held by their previous owners. The previous owners have paid or retained liability for the fees for all generation prior to the purchase dates of those plants. The fees payable to the DOE may be adjusted in the future to assure full recovery. Entergy considers all costs incurred for the disposal of spent nuclear fuel, except accrued interest, to be proper components of nuclear fuel expense. Provisions to recover such costs have been or will be made in applications to regulatory authorities for the Utility plants. Entergy'sEntergy’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1 billion.$1.5 billion (exclusive of amounts relating to Entergy plants that were paid or are owed by prior owners of those plants).
The permanent spent fuel repository in the U.S. has been legislated to be Yucca Mountain, Nevada. The DOE is required by law to proceed with the licensing (the DOE filed the license application in June 2008) and, after the license is granted by the NRC, proceed with the repository construction and commencement of receipt of spent fuel. Because the DOE has not begun accepting spent fuel, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts. The DOE continues to delay meeting its obligation. Moreover, the Obama administration has expressed its intentiontaken specific steps to discontinue the Yucca Mountain project and plans to study a new spent fuel strategy. Therefore,Such actions included a motion to the NRC to withdraw the license application with prejudice and the establishment of a commission to develop recommendations for alternative spent fuel storage solutions. DOE and NRC actions to shut down the Yucca Mountain process are subject to current litigation, and the government has taken no effective action to date related to the recommendations of the appointed spent fuel study commission. Accordingly, large uncertainty remains regarding the time frame under which the DOE will begin to accept spent fuel from Entergy's facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at Entergy's nuclear sites.
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As a result of the DOE's failure to begin disposal of spent nuclear fuel in 1998 pursuant to the Nuclear Waste Policy Act of 1982 and the spent fuel disposal contracts, Entergy's nuclear owner/licensee subsidiaries have incurred and will continue to incur damages. In November 2003 these subsidiaries, except for the owner of Palisades, began litigation to recover the damages caused by the DOE's delay in performance. In two separate decisions in October 2007 the U.S. Court of Federal Claims awarded $10.0 million jointly to System Fuels, System Energy, and SMEPA, and awarded $48.7 million jointly to System Fuels and Entergy Arkansas in damages related to the DOE's breach of its obligations. BothIn a revised decision issued in March 2010, the court awarded $9.7 million jointly to System Fuels, System Energy, and SMEPA. Also in March 2010, in two separate decisions, are subjectthe court awarded $106.1 million to appealEntergy Nuclear Indian Point 2, and $4.2 million to Entergy Nuclear Generation Company (the owner of Pilgrim). In September 2010 the court awarded $46.6 million to Entergy Nuclear Vermont Yankee. All of these decisions were appealed by the DOE and the DOE has filed an appeal of the Entergy Arkansas decision withto the U.S. Court of Appeals for the Federal Circuit. TheCircuit (Federal Circuit). In September 2011 the Federal Circuit affirmed most of the Entergy Nuclear Generation Company award, but remanded to the trial court for recalculation of certain damages. In January 2012 the Federal Circuit affirmed the System Fuels and Entergy Arkansas award in large part, and reversed the trial court’s denial of certain damages sought, but remanded to the trial court for recalculation of certain damages. Also in January
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2012, the Federal Circuit affirmed the System Fuels, System Energy and SMEPA award, and reversed the trial court’s denial of certain damages, raising the final award to $10.2 million, and in April 2012 the U.S. Court of Federal Claims issued a final judgment and Entergy received payment of that amount from the U.S. Treasury in June 2012. In April 2012 the U.S. Court of Federal Claims entered a final judgment in the amount of approximately $4 million in the Pilgrim case. In October 2012 the DOE again appealed that decision to the Federal Circuit. In April 2012 the Federal Circuit issued a decision in the appeal in the Entergy Nuclear Indian Point 2 case. In that decision, the Federal Circuit reversed certain damages awarded to Entergy, but also reversed the trial court, butcourt's denial of certain overhead costs. The revisions to the award reduced the net amount from approximately $106 million to approximately $103 million, and Entergy received payment of that amount from the U.S. Treasury in August 2012. In June 2012 the Federal Circuit issued a DOEdecision in the appeal is likely upon issuance of the final decision.Vermont Yankee case. In that decision, the Federal Circuit reversed certain damages awarded to Entergy, but again reversed the trial court’s denial of certain overhead costs. The revisions to the award reduced the net amount from approximately $47 million to approximately $41 million. On December 31, 2012, time for any appeals of the Vermont Yankee judgment expired without any appeals being filed, and that judgment became final. In September 2012, Entergy Nuclear Palisades, LLC filed suit against the DOE for damages from the DOE's breach of the spent fuel disposal contract accruing at Palisades and Big Rock Point since the date of acquisition of those sites from Consumers Energy Company in 2007. Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, and cannot predict the timing of any eventual receipt from the DOE of the U.S. Court of Federal Claims damage awards.
Pending DOE acceptance and disposal of spent nuclear fuel, the owners of nuclear plants are providing their own spent fuel storage. Storage capability additions using dry casks began operations at Palisades in 1993, at ANO in 1996, at FitzPatrick in 2002, at River Bend in 2005, at Grand Gulf in 2006, and at Indian Point and Vermont Yankee in 2008.2008, and at Waterford 3 in 2011. These facilities will be expanded as needed. Current on-site spent fuel storage capacity at Waterford 3 and Pilgrim is estimated to be sufficient until approximately 2012 and 2014, respectively; by which time dry cask storage facilities are planned to be placed into service at these units.that unit.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Gulf States Louisiana, andEntergy Louisiana, Entergy Texas, Entergy Louisiana, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, the portion of River Bend subject to retail rate regulation, Waterford 3, and Grand Gulf, respectively. These amountsThe collections are deposited in trust funds that can only be used for future decommissioning costs. Entergy periodically reviews and updates the estimated decommissioning costs to reflect inflation and changes in regulatory requirements and technology, and then makes applications to the regulatory authorities to reflect, in rates, the changes in projected decommissioning costs.
In June 2001, Entergy Arkansas received notification from the NRC of approval forFollowing a renewed operating license authorizing operations at ANO 1 through May 2034. In July 2005, Entergy Arkansas received notification from the NRC of approval for a renewed operating license authorizing operations at ANO 2 through July 2038. Entergy Arkansas' projections showed that with the assumption of 20 years of extended operational life for both units, the decommissioning fund balances with earnings over the extended life would be sufficient to decommission both units. Pursuant to APSC approval, which was granted based on assumption of renewed licenses for ANO 1 and 2, beginningreview in 2001 Entergy Arkansas stopped collecting funds to decommission ANO 1 and 2. The APSC requires Entergy Arkansas to update every five years the estimated costs to decommission ANO. In March 2009, Entergy Arkansas filedconcluded that there was a funding shortfall for Vermont Yankee of approximately $40 million, which it satisfied with the APSC its fourth five-year estimate of ANO decommissioning costs. The updated estimate indicated the cost to decommission the two ANO units would be $1,265 million.
In December 2002,a $40 million guarantee from Entergy Corporation that is still in place. On July 28, 2010, the LPSC approved a settlement between Entergy Gulf States, Inc. and the LPSC staff. The settlement included, among other things, the requirement to cease collection of funds to decommission River Bend based on an assumed license renewalincreased decommissioning collections for River Bend.
As part of the Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy. As part of the Indian Point 1 and 2 purchase, Entergy also funded an additional $25 million to the decommissioning trust fund. As part of the Palisades transaction, Non-Utility Nuclear assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, Non-Utility Nuclear will dismantle the spent fuel storage facility and complete site decommissioning. Non-Utility Nuclear expects to fund this activity from operating revenue, and Non-Utility Nuclear is providing $5 million in credit support to provide financial assurance for this obligation to the NRC.
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On June 18, 2009, the NRC issued letters indicating that the NRC staff had concluded that there were shortfalls in the amount of decommissioning funding assurance provided for Indian Point 2, Vermont Yankee, Palisades, Waterford 3 and the Louisiana regulated share of River Bend. The NRC staff conducted a telephone conference withBend and on December 13, 2010, the PUCT approved increased decommissioning collections for the Texas share of River Bend, to address previously identified funding shortfalls. Entergy on this issue on June 29, 2009,currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and Entergy agreed to submit a plan by August 13, 2009, for addressingtrust fund performance will ultimately determine the identified shortfalls. In its August 13, 2009 submittal, Entergy provided updated analyses to the NRC that indicated that there was no current shortfall in the amountsadequacy of the required decommissioning funding assurance for Palisades and Indian Point 2, based upon the balances as of July 31, 2009 and an analysis of the costs that would be incurred if Entergy elected to use a sixty-year period of safe storage for decommissioning, as permitted by the NRC's rules. The NRC accepted the analyses regarding Palisades and Indian Point 2 by letters dated December 12, 2009 and December 28, 2009, and with respect to each plant, the NRC concluded that no further action was required. For Vermont Yankee, Entergy concluded that, based upon the balances as of July 31, 2009 and an analysis of the costs that would be incurred if Entergy elected to use a sixty-year period of safe storage for decommissioning, there was a shortfall of approximately $58 million, which could be satisfied with additional financial assurance in a current dollar value of approximately $51 million. Entergy also indicated that it planned to address this shortfall by December 31, 2009 by providing a financial assurance mechanism that is consistent with the regulatory requirements and acceptable to the NRC. A subsequent submittal to the NRC indicated that increases in the decommissioning fund, as of September 30, 2009, have lowered the shortfall to approximately $40 million, or approximately $35 million on a current dollar basis. This submittal proposed using a corporate guarantee as financial assurance, and a corporate guarantee in the amount of $40 million was executed by December 31, 2009 for this purpose. For Waterford 3 and River Bend, Entergy made the appropriate filings by December 31, 2009 with its retail regulators that request increases in rates to address the shortfalls identified by the NRC.amounts.
For the Indian Point 3 and FitzPatrick plants purchased in 2000, NYPA retained the decommissioning trusts and the decommissioning liability.liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA has the rightrights to require the Entergy subsidiaries to assume each of the decommissioning liabilityliabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to Entergy.the Entergy subsidiaries. If the decommissioning liability isliabilities are retained by NYPA, the responsible Entergy subsidiary will perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 17 to the financial statements.
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Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase insurance and participate in a secondary insurance pool that provides insurance coverage for the public in the event of a nuclear power plant accident. The costs of this insurance are borne by the nuclear power industry. Congress amended and renewed the Price-Anderson Act in 2005 for a term through 2025. The Price-Anderson Act limits contingent liability for a single nuclear incident to approximately $117.5 million per reactor (with 104 nuclear industry reactors currently participating). Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, System Energy, and Entergy's Non-Utility Nuclear businessEntergy Wholesale Commodities have protection with respect to this liability through a combination of private insurance and an industry assessment program, as well as insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units. The Price-Anderson Act and insurance applicable to the nuclear programs of Entergy are discussed in more detail in Note 8 to the financial statements.
Environmental Regulation
Entergy'sEntergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy'sEntergy’s businesses are in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance requirements and costs cannot be precisely estimated. Except to the extent discussed below, at this time compliance with federal, state, and local provisions regulating the discharge of materials into the environment, or otherwise protecting the environment, is incorporated into the routine cost structure of Entergy'sEntergy’s businesses and is not expected to have a material adverse effect on their competitive position, results of operations, cash flows, or financial position.
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Clean Air Act and Subsequent Amendments
The Clean Air Act and its subsequent Amendments establishedamendments establish several programs that currently or in the future may affect Entergy'sEntergy’s fossil-fueled generation facilities and, to a much lesser extent, certain operations at nuclear and other facilities. Individual states also operate similar independent state programs or delegated federal programs that may include requirements more stringent than federal regulatory requirements. These programs include:
| · | New source review and preconstruction permits for new sources of criteria air pollutants and significant modifications to existing facilities; |
| · | Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx); |
| · | Nonattainment area programs for control of criteria air pollutants;pollutants, which could include fee assessments for air pollutant emission sources under Section 185 of the Clean Air Act if attainment is not reached in a timely manner; |
| · | Hazardous air pollutant emissions reduction program;programs; |
| · | Interstate Air Transport; |
| · | Operating permits program for administration and enforcement of these and other Clean Air Act programs; and |
| · | Regional Haze and Best Available Retrofit Technology programs. |
New Source Review (NSR)
Preconstruction permits are required for new facilities and for existing facilities that undergo a modification that results in a significant net emissions increase and is not classified as routine repair, maintenance, or replacement. Units that undergo a non-routine modification must obtain a permit modification and may be required to install additional air pollution control technologies. Entergy has an established process for identifying modifications requiring additional permitting approval and has followed the
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regulations and associated guidance provided by the states and the federal government with regard to the determination of routine repair, maintenance, and replacement. In recent years, however, the EPA has begun an enforcement initiative, aimed primarily at coal plants, to identify modifications that it does not consider routine and that have failed tofor which the unit did not obtain a permit modification. Entergy to date has not been included in any of these enforcement actions. Nevertheless, variousmodified permit. Various courts and the EPA have been inconsistent in their judgments regarding what modifications that are considered routine.
In April 2007February 2011, Entergy received a request from the U.S. Supreme Court ruledEPA for several categories of information concerning capital and maintenance projects at the White Bluff and Independence facilities, both located in Arkansas, in order to determine compliance with the Clean Air Act. In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. Entergy responded to both requests. Neither EPA request for information alleged that the applicabilityfacilities are in violation of Clean Air Act NSR requirements is not limited only to modifications that create an increase in hourly emission rates, but also can apply to modifications that create an increase in annual emission rates (Environmental Defense v. Duke Energy). This Supreme Court decision has resulted in a renewed effort by the EPA to bring enforcement actions against electric generating units for major non-permitted facility modifications.law.
Acid Rain Program
The Clean Air Act provides SO2 allowances to most of the affected Entergy generating units for emissions based upon past emission levels and operating characteristics. Each allowance is an entitlement to emit one ton of SO2 per year. Plant owners are required to possess allowances for SO2 emissions from affected generating units. Virtually all Entergy fossil-fueled generating units are subject to SO2 allowance requirements. Entergy could be required to purchase additional allowances when it generates power using fuel oil. Fuel oil usage is determined by economic dispatch and influenced by the price of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.
Ozone Nonattainment
Entergy Gulf States Louisiana and Entergy Texas each operateoperates one fossil-fueled generating unitsunit (Lewis Creek) in a geographic areasarea that areis not in attainment of the currently-enforced national ambient air quality standards (NAAQS) for ozone. The Louisiana nonattainment area that affects Entergy Gulf States LouisianaTexas is the Baton RougeHouston-Galveston-Brazoria area. Texas nonattainment areas that affect Entergy Texas are the Houston-Galveston-Brazoria and the Beaumont-Port Arthur areas. Areas in nonattainment are classified as "marginal","marginal," "moderate," "serious," or "severe." When an area fails to meet the ambient air standard, the EPA requires state regulatory authorities to prepare state implementation plans meant to cause progress toward bringing the area into attainment with applicable standards.
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In April 2004, the EPA issued a final rule, effective June 2005, revoking a 1-hour ozone standard, including designations and classifications. In a separate action over the same period, the EPA enacted 8-hour ozone nonattainment classifications and stated that areas designated as nonattainment under a new 8-hour ozone standard shall have one year to adjust to the new requirements with submittal of a new attainment plan.
The Baton Rouge area was classified as a ''marginal" nonattainment area under the 8-hour standard with an attainment date of June 15, 2007. On March 21, 2008, the EPA published a notice that the Baton Rouge area had failed to meet the standard by the attainment date and that the EPA was proceeding with a "bump-up" of the area to the next higher nonattainment level. The Baton Rouge area is now classified as a "moderate" nonattainment area with an attainment date of June 15, 2010.
The Beaumont-Port Arthur area was originally classified as a "marginal" nonattainment area under the 8-hour standard with an attainment date of June 15, 2007. On March 18, 2008, the EPA published a notice that the Beaumont-Port Arthur area had failed to meet the standard by the attainment date based on the area's 2004-2006 monitoring data and that the EPA was proceeding with a "bump-up" of the area to the next higher nonattainment level. The 2005-2007 monitoring data showed the area to be in attainment, however, and on July 9, 2008, the Texas Commission on Environmental Quality proposed a plan for EPA re-designation of the area from nonattainment to attainment under the 8-hour ozone standard.
The Houston-Galveston-Brazoria area was originally classified as "moderate" nonattainment under the 8-hour ozone standard with an attainment date of June 15, 2010. On June 15, 2007, the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from "moderate" to "severe." On October 1, 2008,"severe" and the EPA granted the request by the Texas governor to voluntarily reclassify the Houston-Galveston-Brazoria area from a "moderate" 8-hour ozone nonattainment area to a "severe" 8-hour ozone nonattainment area. The EPA also set April 15, 2010, as the date for the State of Texas to submit a revised state implementation plan addressing the "severe" ozone nonattainment area requirements of the Clean Air Act.on October 1, 2008. The area's new attainment date for the 8-hour ozone standard is as expeditiously as practicable, but no later than June 15, 2019.
In December 2006, the EPA's revocation of the 1-hour ozone standard was rejected in a judicial proceeding. As a result, numerous requirements can return for areas that fail to meet 1-hour ozone levels by dates set by the law. These requirements include the potential to increase fees significantly for plants operating in these areas. In addition, it is possible that new emission controls may be required. Specific costs of compliance cannot be estimated at this time, but Entergy is monitoring development of the respective state implementation plans and will develop specific compliance strategies as the plans move through the adoption process. Additionally, in February 2010, the EPA published a determination that the Baton Rouge area has reached attainment status for the former 1-hour ozone level. This determination may reduce or eliminate any fees required in the area.
In March 2008, the EPA revised the National Ambient Air Quality StandardNAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. The LDEQ recommended that eleven parishes beOn April 30, 2012, the EPA released its final non-attainment designations for the 2008 ozone NAAQS. In Entergy’s utility service area, the Houston-Galveston-Brazoria, Texas; Baton Rouge, Louisiana; and Memphis, Tennessee/Mississippi/Arkansas areas were designated as nonattainment forin “marginal” nonattainment.
For these marginal areas attainment must be demonstrated no later than December 31, 2015 (with EPA evaluating whether the 75 parts per billionarea attained the standard based on monitored ozone standard. Entergy Gulf States Louisiana has two fossil plants and Entergy Louisiana has one fossil plant affected by this recommendation.data from 2013-2015). In Arkansas, the governor recommended that Pulaski County be designated in nonattainment with the new ozone standard, where two of Entergy Arkansas' smaller facilities are located. These recommendations have not been approved yet by thefinal designation rule, EPA and in September 2009 the EPA announcedstates that it is reconsideringanticipates the 75 parts per billion standard and may lower it further. Lowering the standard would cause the need for additional analysis of county and parish attainment status. On January 7, 2010, the EPA proposed to set the primary 8-hour ozone standard at a level between 60 to 70 parts per billion. The proposal is expected to result in 11 additional Entergy facilities operating inmarginal areas designated as non-attainment for ozone. Following nonattainment designation, states will be requiredable to develop state implementation plansattain by that outline control requirements that will enabledate based upon reductions attendant with other rules and programs such as the affected counties and parishes to reach attainment status.interstate transport rules. Entergy facilities in these areas may be subject to installation of NOxNOx controls, but the degree of control will remain unknown until the state implementation plansstates are developed.further along in implementing in the marginal areas. Entergy will continue to monitor and engage in the statestate’s implementation plan development process in Entergy states.
Potential SO2 Nonattainment
The EPA issued a final rule in June 2010 adopting an SO2 1-hour national ambient air quality standard of 75 parts per billion. The EPA designations for counties in attainment and nonattainment were originally due in June 2012, but the EPA has indicated certain of these designations will occur by June 2013. States must then submit implementation plans designed to return the areas to attainment to the EPA for approval. Additional capital projects or operational changes may be required for Entergy facilities in these areas.
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Hazardous Air Pollutants
In March 2005,The EPA released the EPA issued a federalfinal Mercury and Air Toxics Standard (MATS) rule in December 2011 and the rule became effective in April 2012. Entergy currently is developing compliance plans to cap and reduce mercury emissions frommeet requirements of the rule, which could result in significant capital expenditures for Entergy’s coal-fired power plants. Theunits. Compliance with MATS is required by the Clean Air Mercury Rule (CAMR) established "standardsAct within three years, or by 2015, although certain extensions of performance" limiting mercury emissionsthis deadline are available from newstate permit authorities and existing coal-fired power plants and created a market-based cap-and-trade program intended to reduce nationwide utility emissions of mercury in two distinct phases. The rule was challenged in the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit). On February 8, 2008, the D.C. Circuit struck down CAMR and remanded the rule to the EPA for further consideration. The EPA likely will proceed with developing a Maximum Achievable Control Technology (MACT) retrofit standard for coal and oil-fired units. In 2009 the EPA issued an Information Collection Request to gather data needed for promulgation of Hazardous Air Pollutant regulations. It is currently expected that the EPA will propose a mercury MACT rule in 2011 with a final rule in 2013. Entergy is continuing to conduct mercury research through coordination with the Electric Power Research Institute (EPRI) and others and remains involved in the current rulemaking process.EPA.
InterstateCross-State Air TransportPollution
In March 2005, the EPA finalized the Clean Air Interstate Rule (CAIR), which iswas intended to reduce SO2 and NOxNOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule requiresrequired a combination of investment of capital to install pollution control equipment and increased operating costs through the purchase of emission allowances. Entergy's capital investment and annual allowance purchase costs under the CAIR will depend on the economic assessment of NOx and SO2 allowance markets, the cost of control technologies, and unit usage. Entergy began implementation in 2007, including installation of controls at several facilities and the development of an emission allowance procurement strategy.
Based on several court challenges, the CAIR was vacated and remanded to the EPA by the D.C. Circuit in 2008. The effectcourt allowed the CAIR to become effective in January 2009, while the EPA revised the rule. On July 7, 2011, the EPA released its final Cross-State Air Pollution Rule (CSAPR, which previously was referred to as the Transport Rule). The rule was directed at limiting the interstate transport of emissions of NOx and SO2 as precursors to ozone and fine particulate matter. The final rule provided a significantly lower number of allowances to Entergy’s Utility states than did the draft rule. Entergy’s capital investment and annual allowance purchase costs under the CSAPR would depend on capital spending could be offset by emissionthe economic assessment of NOx and SO2 allowance markets, which allow for purchases or usethe cost of allocated allowances; however, the allocation of the emission allowancescontrol technologies, generation unit utilization, and the set upavailability and cost of the market will determine the ultimate cost to Entergy. Entergy believes that the original allocation was unfairly skewed towards states with relatively higher emissions by the use of a fuel-adjustment factor. purchased power.
Entergy filed a challenge to this aspect ofpetition for review with the rule in the U.S.United States Court of Appeals for the DistrictD.C. Circuit and a petition with the EPA for reconsideration of Columbia Circuit (D.C. Circuit).
The CAIR was vacated bythe rule and stay of its effectiveness. Several other parties filed similar petitions. On December 30, 2011, the D.C. Circuit in July 2008. The court found thatCourt of Appeals stayed CSAPR and instructed the EPA failed to address basic obligations undercontinue administering CAIR, pending further judicial review. In August 2012 the Clean Air Act's "good neighbor" provision regarding "upwind" states' contribution to air quality impairmentcourt issued a decision vacating CSAPR and leaving CAIR in "downwind" states. Theplace pending the promulgation of a lawful replacement for both rules. In January 2013 the court also ruled favorably on Entergy's challenge, finding thatdenied petitions for reconsideration filed by the EPA exceeded its statutory authority whenand certain states and intervenors. Entergy is complying with CAIR as it included a fuel adjustment factorcontinues to calculatebe implemented until further instruction from the state NOx emission budgets.court or the EPA.
On December 23, 2008, the D.C. Circuit remanded the CAIR decision to the EPA without vacatur, allowing the CAIR to become effective on January 1, 2009, while EPA revises the rule. The revised rule must address all the flaws identified in the D.C. Circuit decision, including the use of a fuel adjustment factor and the use of acid rain SO2 allowances for the CAIR. Entergy has reactivated its compliance effort for the CAIR based on this court ruling. The EPA is expected to issue a proposed CAIR replacement rule in 2010.
Regional Haze
In June 2005, the EPA issued its final Best Available Retrofit Control Technology (BART)Clean Air Visibility Rule (CAVR) regulations that could potentially result in a requirement to install SO2 and NOxpollution control technology as Best Available Retrofit Control Technology (BART) on certain of Entergy'sEntergy’s coal and oil generation units. The rule leaves certain BARTCAVR determinations to the states. The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the Clean Air Visibility Rule.CAVR. The ADEQ determined that Entergy Arkansas'Arkansas’s White Bluff power plant affects a Class I AreaArea’s visibility and will be subject to the EPA'sEPA’s presumptive BART requirements to installlimits, which likely would require the installation of scrubbers and low NOx burnersNO. x burners. Under currentthen-current state regulations, the scrubbers would have had to be operational by October 2013. Entergy Arkansas filed a petition in December 2009 with the Arkansas Pollution Control and Ecology Commission
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requesting a variance from this deadline however, because the EPA has not approved Arkansas' Regional Haze SIP and the EPA has recentlyhad expressed concerns about Arkansas'Arkansas’s Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval. Entergy Arkansas'Arkansas’s petition requestsrequested that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP. The Arkansas Pollution Control and Ecology (PC&E) Commission adopted a procedural schedule that includes a public hearing and a comment period endingapproved the variance in March 2010 with2010. In October 2011 the expectation thatEPA released a proposed rule addressing the variance could be considered atArkansas Regional Haze SIP. In the Commission's March 26, 2010 meeting. The timeline forproposal the EPA action ondisapproved a large portion of the Arkansas Regional Haze SIP, is uncertainincluding the emission limits for NOx and SO2 at this time.White Bluff. The final rule was published, mostly unchanged, on
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March 12, 2012 and became final on April 11, 2012. The EPA did not issue a Federal Implementation Plan for regional haze requirements because Arkansas has indicated it wishes to revise and resubmit its SIP. There will be a two-year timeframe in which the EPA must either approve a revised SIP issued by Arkansas or issue a Federal Implementation Plan. These decisions will impact the timing and level of control installation at White Bluff.
Fine Particle (PM2.5) National Ambient Air Quality Standard
In March 2009, Entergy Arkansas made a filing with the APSC seeking a declaratory order that the White Bluff project is in the public interest. In May 2009 the APSC Staff filed a motion requesting that the APSC require Entergy Arkansas to file testimony on several issues. InOn December 2009, in response to14, 2012, the EPA concerns regarding Arkansas' Regional Haze SIP,released regulations that lowered the APSC suspendedNAAQS for fine particle pollution or PM2.5. Currently, the procedural scheduleHouston-Galveston-Brazoria counties area in Texas and Pulaski County in Arkansas are expected to be in non-attainment of the proceeding.new NAAQS. The EPA projections are that these areas will be in attainment by 2020 due to emission reductions from other EPA and state regulations.
Currently,The EPA anticipates making initial attainment/nonattainment designations by December 2014, with those designations likely becoming effective in early 2015. Following nonattainment designation, states with areas designated nonattainment will be required to develop state implementation plans that outline control requirements that enable the White Bluff project is suspended, butaffected counties and parishes to reach attainment status. States would have until 2020 (five years after designations are effective) to meet the latest conceptual cost estimate indicated thatrevised annual PM2.5 standard. A state may request a possible extension to 2025 depending on the severity of an area’s fine particle pollution problems and the availability of pollution controls. Entergy Arkansas' share of the project could cost approximately $465 million. The plant wouldwill continue to operate during construction, although an outage would be necessary to completemonitor and engage in the tiestate’s implementation process in of the scrubbers. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis.states.
Potential Legislative, Regulatory, and Judicial Developments (Air)
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives relating to the reduction of emissions that are under consideration at the federal, state, and local level. Because of the nature of Entergy'sEntergy’s business, the adoptionimposition of eachany of these initiatives could affect itsEntergy’s operations. Entergy continues to monitor these initiatives and activities in order to analyze their potential operational and cost implications. These initiatives include:
| · | designation by the EPA and state environmental agencies of areas that are not in attainment with national ambient air quality standards; |
| · | introduction of several bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2,NOx, SO2, mercury, and CO2carbon dioxide and other greenhouse gasair emissions. New legislation or regulations applicable to stationary sources could take the form of market-based cap-and-trade programs, direct requirements for the installation of air emission controls onto air emission sources, or other or combined regulatory programs. Entergy cannot estimate the effect of any future legislation at this time due to the uncertainty of the regulatory format; |
| · | efforts to implement a voluntary program intended to reduce CO2 emissions and efforts in Congress or at the EPA to establish a mandatory federal CO2carbon dioxide emission control structure;
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| · | passage and implementation of the Regional Greenhouse Gas Initiative by several states in the northeast U.S.northeastern United States and similar actions in other regions of the Midwest and California;United States; |
| · | efforts on the state and federal level to codify renewable portfolio standards, a clean energy standard, or a similar mechanism requiring utilities to produce or purchase a certain percentage of their power from defined renewable energy sources;sources or energy sources with lower emissions; |
| · | efforts to develop more stringent state water quality standards, effluent limitations for Entergy’s industry sector, stormwater runoff control regulations, and cooling water intake structure requirements; |
| · | efforts to restrict the previously-approved continued use of oil-filled equipment containing certain levels of PCBs; and |
| · | efforts by certain external groups to encourage reporting and disclosure of CO2carbon dioxide emissions and risk. Entergy has prepared responses for the Carbon Disclosure Project'sProject’s (CDP) annual questionnaire for the past several years and has given permission for those responses to be posted to CDP'sCDP’s website. |
Entergy continues to support national legislation that would increase planning certainty for electric utilities while addressing carbon dioxide emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low-emitting gas-fired and nuclear generation technologies, Entergy has a low overall carbon dioxide emission “intensity,” or rate of carbon dioxide emitted per kilowatt-hour of electricity generated. In addition to these initiatives, certain states and environmental advocacy groups are seeking judicial action to require the EPA to promulgate regulations under existing provisionsanticipation of the Clean Air Act to control CO2 emissions from power plants. In April 2007potential imposition of carbon dioxide emission limits on the U.S. Supreme Court held that the EPA is authorized by the current provisions of the Clean Air Act to regulate emissions of CO2 and other "greenhouse gases" as "pollutants" (Massachusetts v. EPA) and that the EPA is required to regulate these emissions from motor vehicles if the emissions are anticipated to endanger public health or welfare. The Supreme Court directed the EPA to make further findings in this regard. The decision is expected to affect a similar case pendingelectric industry in the U.S. Courtfuture, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of Appeals for the D.C. Circuit (Coke Oven Environmental Task Force v. EPA) considering the same question under a similar Clean Air Act provision in the context of CO2 emissions from electric generating units. Entergy participated as a friend of the court in Massachusetts v. EPA and has been granted the same status in Coke Oven. Entergy will continueformal program to advocate in support of reasonable market-based regulation of CO2. Entergy has also supported the comments of various industry groupsstabilize power
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advocating national legislation to address CO2 emissions instead of attempting to regulate under the provisions of the Clean Air Act. Entergy continues to monitor these and similar actions in order to analyze their potential operational and cost implications and benefits.
In 2009, the EPA published an "endangerment finding" stating that the emission of greenhouse gases "may reasonably be anticipated to endanger public health or welfare" and that the emission of these pollutants from mobile sources (such as cars and trucks) contributes to this endangerment. The EPA has stated that the endangerment finding itself does not create any immediate requirements for any emissions source; however, in 2009 the EPA also proposed rules limiting the emissions of certain greenhouse gases, including CO2, from cars and light trucks, adopting a policy that the "actual control" of greenhouse gas emissions (such as by the mobile source rule) would trigger the application of new source review permitting requirements for stationary sources under section 165 of the Clean Air Act, and creating a threshold of 25,000 tons of emissions for the application of new source review permitting for new sources and 10,000 to 25,000 tons for modifications. These changes, taken together and if finalized by the EPA, would likely require new stationary sources of greenhouse gas emissions and significant modifications of existing sources to undergo a new source review permitting process that would include the required application of best available control technology (BACT) for the control of such emissions to the stationary source. The likely outcome of permit-by-permit determinations of required BACT and the associated costs is, at this time, uncertain. Additionally, subsequent to the endangerment finding, the EPA may be required to develop new source performance standards for both new and existing sources of greenhouse gas emissions. The details of these standards and any required operational changes are uncertain.
In anticipation of the potential imposition of CO2 emission limits on the electric industry in the future, Entergy has initiated actions designed to reduce its exposure to potential new governmental requirements related to CO2 emissions. These voluntary actions included establishment of a formal program to stabilize power plant CO2carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in actually reducing emissions below 2000 levels. Entergy has now established a second formal voluntary program to stabilize power plant CO2 emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010 and continues to support national legislation that would increase planning certainty for electric utilities while addressing emissions in a responsible and flexible manner. By virtue of its proportionally large investment in low- or non-emitting gas-fired and nuclear generation technologies, Entergy's overall CO2 emission "intensity," or rate of CO2 emitted per kilowatt-hour of electricity generated, is already among the lowest in the industry. Total CO2carbon dioxide emissions representing Entergy'sEntergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 49.6 million tons in 2001, 44.2 million tons in 2002, 36.8 million tons in 2003, 38.3 million tons in 2004,and 35.6 million tons in 2005, 38.8 million tons in 2006, 40.2 million tons in 2007, 43.9 million tons in 2008, and 39.8 million tons in 2009.2005. In 2006, Entergy changed its method of calculating emissions and now includes emissions from controllable power purchases as well as its ownership share of generation, which accounts forgeneration. Entergy established a second formal voluntary program to stabilize power plant carbon dioxide emissions and emissions from controllable power purchases at 20% below 2000 levels through 2010. Entergy has extended this commitment through 2020. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the increase beginningUnited States were approximately 46.3 million tons in 2006 compared to the trend for the prior years.2011 and approximately 45.0 million tons in 2012.
Greenhouse Gas Reporting
In September 2009, the EPA finalized a rule to require reporting of several greenhouse gases. This rule will require Entergy to report annually report greenhouse gas emissions from operating power plants and natural gas distribution operations. Entergy has developed compliance plans, is collectingcollected the necessary data, and will reporthas reported as required beginning in 2011.
New Source Performance Standards for Greenhouse Gas Emissions
The EPA announced a schedule for establishing new source performance standards (NSPS) for greenhouse gas (GHG) emissions from power plants and refineries. Under the schedule, the EPA would have issued proposed regulations for power plants by July 26, 2011 and final regulations no later than May 26, 2012. On April 13, 2012, the EPA published the proposed NSPS for GHGs for new sources in the Federal Register. The proposed rule only applies to new units and would limit CO2 emissions for any fossil-fired power plant greater than 25 MW to 1,000 pounds of CO2 per MWh of electricity produced. Concerns have been expressed regarding the proposed rule’s potential applicability to existing facilities that undergo modification. The rule would not apply to certain units such as simple cycle natural gas units and biomass units. Entergy commented on the proposed rule and will continue to monitor and participate in the rulemaking process.
The EPA also agreed with environmental litigants to promulgate a performance standard for GHG emissions applicable to existing power plants and refineries. Although the EPA has not announced a current deadline for this activity, the development of a proposed rule may occur in 2013. Entergy will continue to monitor and participate in the rulemaking process.
Nelson Unit 6 (Entergy Gulf States Louisiana)
Entergy Gulf States Louisiana has self-reported to the LDEQ an annual carbon monoxide (CO) emission limit deviation at the Nelson Unit 6 coal-fired facility for the years 2006-2010 and the failure to report these deviations in semi-annual reporting and in annual Title V compliance certifications. Entergy Gulf States Louisiana is not required to monitor carbon monoxide emissions from Nelson Unit 6 using a continuous emissions monitoring system (CEMS). Stack tests performed in 2010 appear to indicate CO emissions in excess of the maximum hourly limit for three – 1 hour test runs; however, comparison of the 2010 stack tests with the most recent previous tests, from 2006, appear to indicate that the permit limits were calculated incorrectly in the Title V Permit application and should have been higher using the 2006 stack test as the basis. The 2010 test emission levels did not cause a violation of NAAQS. Additionally, the 2010 stack testing, which was performed in compliance with an EPA data request connected to the agency’s development of a new air emissions rule, was not taken during a period of normal and representative operations for Nelson 6. While it is likely that a penalty will be imposed for these permit limit exceedances and non-reporting, the particular facts surrounding this exceedance make it difficult to estimate the size of the penalty. Consideration likely will be given, however, for Entergy Gulf States Louisiana’s self-reporting of the issue and cooperation in resolving the issue.
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Clean Water Act
The 1972 amendments to the Federal Water Pollution Control Act (known as the Clean Water Act) provide the statutory basis for the National Pollutant Discharge Elimination System (NPDES) permit program and the basic structure for regulating the discharge of pollutants from point sources to waters of the United States. The Clean Water Act requires virtually all discharges of pollutants to waters of the United States to be permitted, sectionpermitted. Section 316(b) of the Clean Water Act regulates cooling water intake structures, section 401 of the Clean Water Act requires a water quality certification from the state in support of certain federal actions and approvals, and section 404 regulates the dredge and fill of waters of the United States, including jurisdictional wetlands.
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NPDES Permits and Section 401 Water Quality Certifications
NPDES permits are subject to renewal every five years. Consequently, Entergy is currently in various stages of the data evaluation and discharge permitting process for its Utility power plants and its Non-Utility Nuclear power plants. Additionally, the State of New York has taken the position that a new state-issued water quality certification is required as part of the NRC license renewal process. Therefore, Non-Utility Nuclear'sEntergy Wholesale Commodities’ Indian Point nuclear facility in New York facilities also areis seeking or have obtained, a sectionnew Section 401 certification prior to license renewal.renewal under full reservation of rights.
FitzPatrickIndian Point
As agreed to as settlement of the FitzPatrick discharge permit and water quality certification, Entergy installed Ristroph screens for safely removing fish from intake screens, and plans to install an initial fish return system during the next five-year permit cycle. Additionally, Entergy is undertaking studies regarding the feasibility and effectiveness of relocating FitzPatrick’s offshore intake structure and of additional fish return technologies. The permit issued under the agreement requires thatinvolved in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) initiate a permit modification, triggering Entergy's right to challenge, if New York State decides to require the installation and operation of additional fish return technology. The Clean Water Act permit, water quality certification, and Coastal Zone Management Act consistency determination have now been issued.
Vermont Yankee
Opposition groups appealed a water discharge permit amendment issued to Vermont Yankee pursuant to the state's NPDES program in which the Vermont Agency of Natural Resources (VANR) allowed a small increase in the amount of heat the facility can discharge to the Connecticut River from June 16 to October 14 each year. The VANR permit amendment increases operational flexibility for the required usage rate of the existing cooling towers and for the generation rate of the facility that is especially helpful in conditions of high ambient temperatures or low river flow conditions. The trial of this matter occurred in the Vermont Environmental Court during the summer of 2007. On May 22, 2008, the Vermont Environmental Court entered its judgment and order granting the increased thermal discharge provided in the amendment for the period from July 8 through October 14 each year, but imposing additional management and measurement requirements with respect to the period from June 16 through July 7. Entergy and opposition groups appealed aspects of the ruling to the Vermont Supreme Court. On December 18, 2009, the Vermont Supreme Court affirmed the thermal increase but overturned the Vermont Environmental Court's imposition of additional management and measurement requirements.
Indian Point
Non-Utility Nuclear is involved in an administrative permitting process with the NYSDEC for renewal of the Indian Point 2 and Indian Point 3 discharge permits. In November 2003 the NYSDEC issued a draft permit indicating that closed cycle cooling would be considered the "best“best technology available"available” for minimizing alleged adverse environmental effects attributable to the intake of cooling water at Indian Point, 2 and Indian Point 3, subject to a feasibility determination and alternatives analysis for that technology, if Entergy applied for and received NRC license renewal atfor Indian Point 2 and Indian Point 3. Upon becoming effective, the draft permit also would have required payment of approximately $24 million annually, and an annual 42 unit-day outage period, until closed cycle cooling is implemented. Non-Utility NuclearEntergy is participating in the administrative process to request that the draft permit be modified prior to final issuance, and opposes any requirement to install cooling towers at Indian Point 2 and Indian Point 3. In the past Non-Utility Nuclear notified the NYSDEC that the cost of retrofitting Indian Point 2 and Indian Point 3 with cooling towers likely would cost, in 2003 dollars, at least $740 million in capital costs and an additional $630 million in lost generation during construction.Point.
In the February 2010 feasibility report noted in the paragraph below, Non-Utility Nuclear provided an updated estimate of the cost to retrofit Indian Point 2 and Indian Point 3 with cooling towers. Construction costs for retrofitting with cooling towers are now estimated to be at least $1.19 billion, in addition to lost generation of approximately 14.5 TWh during the estimated 42-week forced outage of both units. Non-Utility Nuclear also proposed an alternative to the cooling towers, the use of Wedgewire screens, that would cost up to approximately $100 million to install. Due to fluctuations in power pricing and because a retrofitting of this size and complexity has never been undertaken, significant uncertainties exist in these estimates and, therefore, they could be materially higher than estimated.
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An August 13, 2008 ruling by the NYSDEC'sNYSDEC’s Assistant Commissioner has restructured the permitting and administrative process, including by applyingthe application of a new economic test designed to implement the U.S. Second Circuit's standard.Circuit Court of Appeals standard in that court’s review of the EPA’s cooling water intake structure rules, which is discussed in the 316(b) Cooling Water Intake Structures section below. The NYSDEC has directed Entergy to develop detailed feasibility information regarding the construction and operation of cooling towers, and alternatives to closed cycle cooling, prior to the issuance of a new draft permit by the NYSDEC staff and commencement of the adjudicatory proceeding. The reports include a visual impact and aesthetics report filed onin June 1, 2009, a plume and emissions report filed onin September 1, 2009, a technical feasibility report due and alternatives analysis filed in February 2010, and an economic report to establish whether the technology, if feasible, satisfies the economic test that is part of the New York standard. Entergy has also requested that the NYSDEC Assistant Commissioner reconsider the New York standard in light of the U.S. Supreme Court decision reversing the Second Circuit'sCircuit’s alternative economic test adopted in the August 13, 2008 ruling. In November 2012 the NYSDEC Assistant Commissioner's delegate issued a decision overturning the alternative economic test adopted in the August 2008 ruling and reestablishing the "wholly disproportionate" test derived from previous New York precedent. The current procedural schedule callswholly disproportionate test considers whether the costs of a technology are wholly disproportionate to the environmental benefits gained from the technology.
In February 2010, Entergy provided to the NYSDEC an updated estimate of the capital cost to retrofit Indian Point 2 and Indian Point 3 with cooling towers. Construction costs for hearingsretrofitting with cooling towers are estimated to commencebe at least $1.19 billion, in 2011.addition to lost generation of approximately 14.5 terawatt-hours (TWh) during the forced outage of both units that is estimated to take at least 42 weeks. Entergy also proposed an alternative to the cooling towers, the use of cylindrical wedgewire screens, the construction costs of which are now expected to be approximately $250 million to $300 million. Because a cooling tower retrofitting of this size and complexity has never been undertaken at an operating nuclear facility, significant uncertainties exist in the capital
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cost estimates and, therefore, the actual capital costs could be materially higher than estimated. Moreover, construction outage-related costs to Entergy have not been calculated because of the significant variability in power pricing at any given time, but they are expected to be significant and may exceed the capital costs. The capital cost estimate for the wedgewire screen construction is also subject to uncertainty. Hearings on certain issues began in 2011 in consolidation with certain issues in the water quality certification matter that is discussed further below. The NYSDEC is expected to consider the information submitted and issue another draft permit with a new best technology available determination, which may or may notcould still be cooling towers. A new comment period and further contested proceedings likely would follow.
OnEntergy submitted its application for a water quality certification to the NYSDEC in April 6, 2009, with a reservation of rights regarding the applicability of the section, Entergy's Indian Point facility submitted a Section 401 in this case. After Entergy submitted certain additional information in response to NYSDEC requests for additional information, in February 2010 the NYSDEC staff determined that Entergy’s water quality certification toapplication was complete. In April 2010 the NYSDEC.NYSDEC staff issued a proposed notice of denial of Entergy’s water quality certification application (the Notice). NYSDEC staff’s Notice triggered an administrative adjudicatory hearing before NYSDEC ALJs on the proposed Notice. The certification, orNYSDEC staff decision does not restrict Indian Point operations, but the issuance of a waiver or exemption of the same,certification is potentially required pursuantprior to NRC issuance of renewed unit licenses.
In June 2011, Entergy filed notice with the NRC that the NYSDEC, the agency that would issue or deny a water quality certification for the Indian Point license renewal process, has taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, has waived its opportunity to require a certification under the provisions of Section 401 of the Clean Water Act asAct. The NYSDEC has notified the NRC that it disagrees with Entergy’s position and does not believe that it has waived the right to require a supporting documentcertification. The NYSDEC ALJs overseeing the agency’s certification adjudicatory process stated in a ruling issued in July 2011 that while the waiver issue is pending before the NRC, the NYSDEC hearing process will continue on selected issues. The judge held a Legislative Hearing (agency public comment session) and an Issues Conference (pre-trial conference) in July 2010 and set certain issues for trial in October 2011, which is continuing into 2013. After the full hearing on the merits, the ALJs will issue a recommended decision to the NRC's license renewalCommissioner who will then issue the final agency decision. On May 13, 2009,A party to the NYSDEC deemedproceeding can appeal the application incomplete and requested additional information. The NYSDEC requested that Entergy respond within 120 days or by September 10, 2009 and setdecision of the deadline for submitting all the requested information as February 13, 2010. Entergy continuesCommissioner to work with the NYSDEC in order to provide the requested additional information and filed two additional reports with the NYSDEC in early February 2010. By law, the NYSDEC must act on the water quality certification application within one year of receipt.state court.
Effluent LimitationsPilgrim Nuclear Power Station
On December 1, 2009,October 9, 2012, EcoLaw, a coalition of several environmental groups, served Entergy Nuclear Generating Company and Entergy Nuclear Operations, Inc. with a notice of intent (NOI) to sue under the EPA publishedClean Water Act for alleged violations at the Pilgrim Nuclear Power Station. The NOI alleges 33,253 discharge permit violations since 1994 (including alleged violations prior to Entergy’s ownership; Entergy purchased the plant in 1999) and seeks $25,000 per violation for a final rule directed at establishing effluent limitation guidelines and standards for the construction and development water pollution point source category. Included within the industry sector affected by this rulemaking are electric utility transmission line and substation construction projects.total of $831,325,000. The effective date of this rulemaking is February 1, 2010. In the rulemaking the EPA is promulgatingClean Water Act states that an alleged violator must be given 60 days notice prior to a series of non-numeric effluent limitations, as well as a numeric effluent limitation for turbidity. All construction sites will be required to meet the series of non-numeric effluent limitations. In general, the non-numeric effluent limitations are a reiterationcitizen’s suit being filed. Early review of the requirement to use siltation and erosion control best management practices directed at stormwater pollution prevention.
Of greater significance to Entergy, construction sitesNOI indicates that disturb ten or more acres of land at one time will be required to monitor discharges from the site and comply with the numeric effluent limitation. If a project initially exceeds the acreage threshold but later, due to permanent stabilization of disturbed areas, falls below the threshold, the numeric effluent limit will no longer apply; consequently, phasing construction projects to limit the amount of soil disturbed at any given time will be an allowed strategy for addressing applicabilitymany of the rulemaking. The EPA is phasingalleged violations were discharges in the numeric effluent limitation over four years to allow permitting authorities adequate time to develop monitoring requirements and to allow the regulated community time to prepare for compliance with the numeric effluent limitation. The numeric limit establishedcurrent EPA facility discharge permit, which the putative plaintiff alleges was improperly issued or modified. An additional NOI was served by this rulemaking is measured as a daily maximum value. DueEcoLaw to the naturesame Entergy parties and the Massachusetts Department of this analytical parameter, samplingEnvironmental Protection alleging violations of state water quality standards and analysisrequesting revocation of the effluent must occur on-site during any day that stormwater run-off occurs at a frequency that will be established by the permitting authority.
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The numeric turbidity limitation will apply to all discharges from the site except on days when total precipitation during the day exceeded the local 2-year, 24-hour storm. If the total precipitation in any one day is greater than the local 2-year, 24-hour storm event, then permittees would still need to sample (because they wouldn't know in advance whether the precipitation on that day was going to exceed the storm size threshold) but the numeric effluent limitation would not apply to discharges for that day. The numeric effluent limitation is applicable to all discharges from the site on subsequent days, however, if there is no 2-year, 24-hour storm event during those days.
In order to achieve the numeric discharge limit, many Entergy construction projects exceeding the acreage threshold will likely be required to utilize chemical flocullants, either applied within a stormwater conveyance in the project watershed or in a stormwater detention basin. In some cases, capture of stormwater run-off and usage of fractionation tanks to temporarily store the water until sufficient settling of suspended soil particles may be required in order to meet the numeric limit.
Construction sites that disturb 20 or more acres at one time will be required to conduct monitoring of discharges from the site and complystate-issued Section 401 Water Quality Certification associated with the numeric effluent limitation beginning 18 months after the effective date of the final rule. Assuming the rulemaking survives any legal challenge, this compliance deadline for 20 acre sites will be August 1, 2011. Construction sites that disturb ten or more acres at one time will be required to conduct monitoring of discharges from the siteplant’s water discharge permit (21-day NOI requirement under state law). On November 2, 2012 and comply with the numeric effluent limitation beginning four years after the effective date of the final rule (February 1, 2014).
The final rule, in part based on the considerations of linear projects (electrical line construction), no longer contains a requirement to install a sediment basin and revisions were madeDecember 7, 2012, Entergy filed responses to the non-numeric effluent limitations based on comments concerning the feasibility at linear projects. However, the EPA disagreed with comments from Entergystate and the Utility Water Act Groupfederal notices of intent to sue. To date, Pilgrim has not received notice that suggested the EPA should either exempt all linear projects from the final rule or from the numeric effluent limitation. The EPAEcoLaw has determined that numeric effluent limitations are feasible for linear projects and passive treatment systems provide flexibility to linear projects to take into account site specific considerations. Additionally, the EPA believes that the permitting authority, which in Entergy's Utility service area is delegated to the states, should exercise discretion when determining the monitoring locations and monitoring frequency for linear construction projects. This establishes what will likely be a very subjective development of requirements for electrical line construction projects.initiated any lawsuits against Pilgrim.
316(b) Cooling Water Intake Structures
The EPA finalized new regulations in July 2004 governing the intake of water at large existing power plants employing cooling water intake structures. The rule sought to reduce perceived impacts on aquatic resources by requiring covered facilities to implement technology or other measures to meet EPA-targeted reductions in water use and corresponding perceived aquatic impacts. Entergy, other industry members and industry groups, environmental groups, and a coalition of northeastern and mid-Atlantic states challenged various aspects of the rule. In January 2007 the United StatesU.S. Second Circuit Court of Appeals for the Second Circuit remanded the rule to the EPA for reconsideration. The court instructed the EPA to reconsider several aspects of the rule that were beneficial to businesses
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affected by the regulated communityrule after finding that these provisions of the rule were contrary to the language of the Clean Water Act or were not sufficiently explained in the rule. In April 2008 the United StatesU.S. Supreme Court agreed to review the decision of the Second Circuit decision on the question of whether the EPA may take into consideration a cost-benefit analysis in developing these regulations, a consideration of potential benefit to businesses affected by the regulated communityrule that the Second Circuit disallowed. In March 2009 the Supreme Court ruled in favor of the petitioners that cost-benefit analysis may be taken into consideration. The EPA may now reissue areissued the proposed rule similar in structure to the rule remandedApril 2011, with finalization anticipated by the Second Circuit, orJuly 27, 2012; however, the EPA may issue a ruleextended the deadline to June 27, 2013. Entergy filed comments with a substantially different structure and effect. Until the EPA issues guidance toon the regulated community on what actions should be taken to comply with the Clean Water Act, and until the form and substance of the new rule itself is determined, it is impossible to estimate the effect of the Supreme Court's decision on Entergy's business. See the discussion above regarding the Indian Point and FitzPatrick permitting processes under similar New York state provisions of law.proposed rule.
At the request of the EPA Region 1 (Boston), Entergy submitted extensive data to the agency in July 2008 concerning cooling water intake impacts at the Pilgrim nuclear power plant. AnalysisThe engineering study, included as part of technologies that may be appropriate for Pilgrim continues, but it appears at this pointthe July 2008 submittal, concluded that cooling towers are not feasible due to restrictions in the plant's condenser design and capacity. Other technologies, such as variable speed pumps and the relocation of the cooling water intake, are under analysis.were also analyzed as part of that submittal. The EPA has not yet responded to the July 2008 submittal.
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Entergy's Utility business generation facilities are likewise in the process of reviewing data, considering implementation options, and providing information required by the current rule to the EPA and the affected states concerning cooling water intake structures. Entergy will continue to review the revised proposed rule and monitor the activities of the EPA and the states toward the implementation of section 316(b) of the Clean Water Act in the wakeAct. Until analysis of the remand of the currentthis revised proposed rule and will respond accordingly. Deadlinesis complete, deadlines for determining compliance with Section 316(b) and for any required capital or operational expenditures are unknown at this time due to the remand of the rule to the EPA.time. As a result, management cannot predict the amounts Entergy will ultimately be required to spend to comply with Section 316(b) and any related state regulations, although such amounts could be significant.
Coastal Zone Management Act
The Coastal Zone Management Act (CZMA) requires federalfederally-permitted activities within a coastal zone to be consistent with the state's federally approvedstate’s federally-approved coastal zone management program. Therefore, a nuclear facility located within a coastal zoneAccordingly, Entergy must obtain a consistency certification fromensure, to the state as partextent applicable, that the requirements of the NRC's license renewal process. Entergy has Non-Utility Nuclear plants that are within coastal zones. Pilgrim has received its consistency determination from the Commonwealth of Massachusetts. Vermont YankeeCZMA, which is not within a coastal zone and does not need a consistency determination.
Inadministered in New York primarily by the Coastal Management Program promotes waterfront revitalization, protects fish and wildlife habitats, protects and enhances scenic and historic areas, and promotes water access and public recreation. As discussed above, FitzPatrick already has obtained its consistency certification.NYSDOS, are satisfied before the NRC may issue renewed licenses for Indian Point expects to file2 and 3. Indian Point filed its consistency determination application with the New York DepartmentNYSDOS, subject to a reservation of Staterights, in mid-2010. The New York Department of StateDecember 2012. On January 16, 2013, NYSDOS determined that additional information was needed, namely the supplement to the NRC’s FSEIS which is expected in April 2013. When the application is deemed complete, the NYSDOS has six months from the date it deemsof the application complete to issue or deny the consistency certification. For additional discussion of the CZMA proceedings regarding New York see “Part 1, Item 1, Entergy Wholesale Commodities – Property - Nuclear Generating Stations.”
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to regularly monitor and report the presence of radioactive material in the environment. Entergy joined other nuclear utilities and the Nuclear Energy Institute in 2006 to develop a voluntary groundwater monitoring and protection program. This initiative began after detection of very low levels of radioactive material, primarily tritium, in groundwater at several plants in the United States, including the Indian Point Energy Center.States. Tritium is a radioactive form of hydrogen that occurs naturally and is also a byproduct of nuclear plant operations. In addition to tritium, other radionuclides have been found in on site ground watergroundwater at Indian Point.nuclear plants.
As part of the groundwater monitoring and protection program, Entergy has: (1) performed reviews of plant groundwater characteristics (hydrology) and historical records of past events on site that may have potentially impacted groundwater; (2) implemented fleet procedures on how to handle events that could impact groundwater; and (3) installed groundwater monitoring wells and began periodic sampling. The program also includes protocols for notifying local officials if contamination is found. To date, radionuclides such as tritium have been detected at Entergy's FitzPatrick, Indian Point, Palisades, Pilgrim, andGrand Gulf, Vermont Yankee, plants.
Entergy identified and addressed two sourcesRiver Bend. Each of the contamination at Indian Point: the Unit 1 and 2 spent fuel pools. In October 2007, the EPA announced that it was consulting with the NRC and the NYSDEC regarding Indian Point. The EPA stated that after reviewing data it confirmed with New York State that there have been no violations of federal drinking water standards for radionuclides in drinking water supplies. Indian Pointthese sites has implemented an extensiveinstalled groundwater monitoring and protection program, including installing approximately 35 monitoring wells, with five to six sampling points per well. Entergy has been working cooperatively with the NRC and the NYSDEC in a split sample program to independently analyze test samples.
At Palisades, Entergy identified tritium in two monitoring wells in December 2007 caused by leakage from the buried piping for a recirculation line. Non-destructive evaluation of the line identified one area of leakage and repairs were completed in 2008. Since early 2008, groundwater from three wells have been sampled and analyzed on a bi-weekly basis. Following the repairs, tritium levels declined in all of the wells and trended downward until one well spiked in March 2009. Additional investigation was performedimplemented a program for testing groundwater at the sites for the presence of tritium. Based on current information, the concentrations and locations of tritium detected at these plants pose no threat to locatepublic health or safety, but each site continues to evaluate the source,results from its groundwater monitoring program.
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including installation of 18 temporary monitoring wells along the path of the buried piping. A new leak location was identified and repairs at the location were completed in mid-summer 2009. However, when the system was put back in service, it became evident from groundwater samples that this same buried piping system was also breached at locations other than at the leak location that had earlier been repaired. Therefore, the piping system was again taken out of service and drained to prevent further leakage into the ground. Subsequently, Entergy decided to abandon this piping and to run new replacement buried pipe for this system. This effort was completed in December 2009. Bi-weekly sampling will continue until the groundwater tritium levels in the monitoring wells are below minimum detection levels.
At Pilgrim, six existing monitoring wells are being sampled and analyzed on a periodic basis. Results continue to show low levels of tritium. A hydrogeological analysis was performed in 2009 to pinpoint the location for six additional wells to further study the situation, and these wells will be installed in 2010. Currently, the detections are believed to be from wash out of atmospheric tritium. Precipitation studies are being performed to confirm this theory.
At FitzPatrick, a sample collected from a reactor building perimeter sump in November 2009 showed elevated levels of tritium. Follow up samples collected in December 2009 from a storm drain that communicates with this sump also found elevated levels of tritium. Investigations are ongoing to determine the source of the tritium and to determine what action should be taken. No elevated levels of tritium have been found in manholes, equipment pits or any of the groundwater monitoring wells.
In January 2010, Vermont Yankee was notified by its off-site analytical laboratory that a sample collected from a groundwater monitoring well in mid-November 2009 showed elevated levels of tritium. Subsequent analyses continue to confirm the presence of an elevated tritium concentration. Investigations are ongoing to determine the source of the tritium, including the installation of additional monitoring wells in February 2010, and to determine what action should be taken. No elevated levels of tritium have been found in any potable water wells located on- or off-site.
Indian Point Units 1 and 2 Hazardous Waste Remediation
As part of the effort to terminate the current Indian Point 2 mixed waste storage permit, Entergy was required to perform groundwater and soil sampling for metals, PCBs and other non-radiological contaminants on plant property, regardless of whether these contaminants stem from onsite activities or were related to the waste stored on-site pursuant to the permit. Entergy believes this permit is no longer necessary for the facility due to an exemption for mixed wastes (hazardous waste that is also radioactive) promulgated as part of the EPA'sEPA’s hazardous waste regulations. This exemption allows mixed waste to be regulated through the NRC license instead of through a separate EPA or state hazardous waste permit. In February 2008, Entergy submitted its report on this sampling effort to the NYSDEC. The report indicated the presence of various metals in soils and groundwater at levels above the NYSDEC cleanup objectives. It does not appear that these metals are connected to operation of the nuclear facility. At the request of the NYSDEC, Entergy submitted a plan onin August 8, 2008 for a study that will identifyidentified the sources of the metals. The NYSDEC recently approved this workplanthe work plan with some conditions related to the need to study whether the soil impact observed may have originated from plant construction materials. This issueIn November 2012, Entergy received a letter from NYSDEC indicating that, based on the additional sampling results, no corrective action is being studied by Entergy to determine if any changes to the workplan are necessary. The NYSDEC may require additional work to define the vertical and lateral extent of the contamination on-site, and evaluate any potential for migration off-site. The NYSDEC plans to use the results of this investigation to determine whether the permit can be terminated and the metals left in place until plant decommissioning or if further investigation or remediation is required. Entergy is unable to determine what the extent or cost of required remediation, if any, will be at this time.
Prior to Entergy'sEntergy’s purchase of Indian Point Unit 1, the previous owner completed the cleanup and desludging of the Unit 1 water storage pool, generating mixed waste (waste that is regulated as both low-level nuclear waste and hazardous waste).waste. The waste currently is stored in the Unit 1 containment building in accordance with NRC regulations controlling low level radioactive waste. The waste is also regulated by the NYSDEC. The NYSDEC requires Entergy toa quarterly survey quarterlyof the availability of any commercial facility capable of treating, processing, and disposing of this waste in a commercially reasonable manner. Entergy continues to review this matter and to conduct its quarterly searches for a commercially reasonable vendor that is acceptable both to the NRC and the NYSDEC. The cost of this disposal cannot be estimated at this time due to the many variables existing in the type and manner of disposal.
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Comprehensive Environmental Response, Compensation, and Liability Act of 1980
The Comprehensive Environmental Response, Compensation, and Liability Act of 1980, as amended (CERCLA), authorizes the EPA to mandate clean-up by, or to collect reimbursement of clean-up costs from, owners or operators of sites at which hazardous substances may be or have been released. Certain private parties also may use CERCLA to recover response costs. Parties that transported hazardous substances to these sites or arranged for the disposal of the substances are also deemed liable by CERCLA. CERCLA has been interpreted to impose strict, joint and several liability on responsible parties. Entergy'sMany states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Non-Utility NuclearEntergy Wholesale Commodities businesses have sent waste materials to various disposal sites over the years, and releases have occurred at Entergy facilities. In addition, environmental laws now regulate certain of Entergy'sEntergy’s operating procedures and maintenance practices that historically were not subject to regulation. Some disposal sites used by Entergy subsidiaries have been the subject of governmental action under CERCLA or similar state programs, resulting in site clean-up activities. Entergy's Utility and Non-Utility Nuclear businessesEntergy subsidiaries have participated to various degrees in accordance with their respective potential liabilities in such site clean-ups and have developed experience with clean-up costs. The affected Entergy companiessubsidiaries have established reservesprovisions for the liabilities for such environmental clean-up and restoration activities. Details of significant CERCLA and similar state program liabilities that are not de minimis are discussed in the "Other“Other Environmental Matters"Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contains two primary regulatory options: (1) regulating CCRs destined for disposal in landfills or received (including stored) in surface impoundments as so-called “special wastes” under the hazardous waste program of RCRA Subtitle C; or (2) regulating CCRs destined for disposal in landfills or surface impoundments as non-hazardous wastes under Subtitle D of RCRA. Under both options, CCRs that are beneficially used in certain processes would remain excluded from hazardous waste regulation.
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Other Environmental Matters
Entergy Gulf States Louisiana and Entergy Texas
Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Gulf States, Inc. and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Gulf States, Inc.'s’s premises (see "“Litigation"” below).
Entergy Gulf States Louisiana is currently involved in the second phase of the remedial investigation of the Lake Charles Service Center site, located in Lake Charles, Louisiana. A manufactured gas plant (MGP) is believed to have operated at this site from approximately 1916 to 1931. Coal tar, a by-product of the distillation process employed at MGPs, was apparently routed to a portion of the property for disposal. The same area has also been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second Administrative Consent Orderadministrative consent order with the EPA to perform removal action at the site. In 2002 approximately 7,400 tons of contaminated soil and debris were excavated and disposed of from an area within the service center. In 2003 a cap was constructed over the remedial area to prevent the migration of contamination to the surface. In August 2005 an administrative order was issued by the EPA requiring that a 10-year groundwater study be conducted at this site. The groundwater monitoring study commenced in January 2006 and is continuing oncontinuing. In 2010 the EPA conducted a quarterly basis.Five Year Review (FYR) of the 10-year groundwater monitoring program at Lake Charles. Negotiations are on-going regarding whether additional actions will be necessary at the site. If additional actions are necessary, site expenditures will increase commensurate with the additional chosen site remedies. Entergy does not have sufficient information at this time to estimate additional site costs, if any. Entergy also has made a payment to the EPA of $275,000 for past agency oversight costs. Entergy Gulf States Louisiana and Entergy Texas each believe that its ultimateremaining responsibility for this site will not materially exceed the existing clean-up provisions of $0.4 million for Entergy Gulf States Louisiana and $0.3$0.4 million for Entergy Texas.
In 1994, Entergy Gulf States Inc. performedLouisiana, L.L.C. initiated an environmental groundwater assessment associated with the submittal of a site assessment in conjunction withpermit application for a construction project at the Louisiana Station Generating Plant (Louisiana Station). In 1995 a furtherthe ongoing assessment confirmed subsurface soil and groundwater impact to three primary areas on the plant site. After validation,Subsequently from 1997 to 1999 soil was removed under guidance and permission of the LDEQ. In 2000, Entergy pursued the final regulatory required remediation of the site’s groundwater and submitted a notification was made tolong-term monitoring plan approved by LDEQ in 2002. Implementation of the LDEQmonitoring plan in 2002 identified the presence of hydrocarbon contributed by a third party. Responsibility has been defined and a phased process was executed to remediate each area of concern.cost sharing has been implemented with a responsible third party identified in the previous characterization phase. The final phase of groundwater clean-up and monitoring phase at Louisiana Station is expected to continue for several more years. The remediationan undefined period of time until groundwater characterization and compliance monitoring meet LDEQ Risk Evaluation and Corrective Action Program groundwater standards for a consistent period of time. Current annual environmental management cost incurred through December 31, 2009 for this site was $6.8 million. Future costs are not expected to exceed Entergy Gulf States Louisiana's existing provision of $0.7 million.is now under $50 thousand per year and includes partial reimbursement by the third party.
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Gulf States, Inc. that the TCEQ believed that Entergy Gulf States, Inc. is one of many potentially responsible parties (PRP) concerning contamination existing at the Spector Salvage Yard proposed state superfund site in Orange, Texas. The TCEQ conducted a removal action
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consisting of the excavation and offsite disposal of contaminated surface soil.
Entergy Gulf States Louisiana, and Entergy Texas do not believe at this time that the former Gulf States Utilities contributed any significant amount of hazardous substances to this site and therefore are contesting liability. Entergy Texas and Entergy Gulf States Louisiana believe that their ultimate responsibility for this site will not exceed their existing clean-up provisions.
Entergy Louisiana, and Entergy New Orleans
Several class action and other suits have been filed in state and federal courts seeking relief from Entergy Louisiana and Entergy New Orleans and others for damages caused by the disposal of hazardous waste and for asbestos-related disease allegedly resulting from exposure on Entergy Louisiana'sLouisiana’s and Entergy New Orleans'Orleans’s premises (see "“Litigation"” below).
During 1993, the LDEQ issued new rules for solid waste regulation, including regulation of wastewater impoundments. Entergy Louisiana has determined that some of its power plant wastewater impoundments were affected by these regulations and may require remediation, repair, or closure. Completion of this work is dependent on pending LDEQ approval of submitted solid waste permit applications. As a result, a total recorded liability in the amount of $1.9 million for Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy New Orleans existed at December 31, 20092012 for ongoing wastewater remediation and repairs and closures. Management believes this reserve to be adequate based on current estimates.
Transmission and distribution storm teams entered wetland areas of Lafourche Parish to restore Entergy Louisiana's Barataria-Golden Meadow line shortly after Hurricane Katrina. A portion of this line crosses property owned by a third party. The landowner has requested that Entergy Louisiana conduct an extensive wetland mitigation program over a ten-acre area and has filed suit against Entergy Louisiana and certain other Entergy subsidiaries concerning the extent of the mitigation. Entergy Louisiana believes that the marsh area affected by its activities is less than 2 acres and that restoration can be conducted to the satisfaction of the U. S. Corps of Engineers and the State of Louisiana for substantially less than the over $4 million claimed by the plaintiff. Entergy Louisiana will meet with the Corps of Engineers and the State of Louisiana to determine the extent of mitigation required by the Clean Water Act and parallel state law.
Entergy Louisiana and Entergy Texas
Damage sustained by Entergy Louisiana's and Entergy Texas' electrical transmission infrastructure due to the effects of Hurricane Gustav and Hurricane Ike necessitated that significant amounts of restoration work occur in areas classified as jurisdictional wetlands and coastal marsh. While measures were taken to minimize the impact in these environmentally-sensitive areas, some level of damage to the wetland and marsh areas likely occurred. Mitigation requirements for these possible impacts have yet to be assessed or required by regulatory authorities. Following Hurricane Katrina and Hurricane Rita, the regulatory authorities deferred assessing mitigation requirements for such impacts pending an evaluation of spontaneous recovery of the marsh and wetlands damaged during line repairs.
Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The TCEQTexas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Texas,Louisiana, Entergy Louisiana,New Orleans, and Entergy New OrleansTexas that the TCEQ believes those entities are PRPs concerning contamination existing at the San Angelo Electric Service Company (SESCO) facility in San Angelo, Texas. The facility operated as a transformer repair and scrapping facility from the 1930s until 2003. Both soil and groundwater contamination exists at the site. Entergy Gulf States, Inc. and Entergy Louisianasubsidiaries sent transformers to this facility during the 1980s.facility. Entergy Gulf States Louisiana, Entergy Texas, Entergy Louisiana, and Entergy Arkansas responded to an information request from the TCEQ and continue to cooperate in this investigation. Entergy New Orleans provided requested information concerning its former status in bankruptcy. Entergy Gulf States Louisiana, Entergy Texas, and Entergy Louisiana joined a group of PRPs responding to site conditions in cooperation with the State of Texas, creating cost allocation models based on review of SESCO documents and employee interviews, and investigating contribution actions against other PRPs. Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Texas have agreed to contribute to the remediation of contaminated soil and groundwater at the site in a measure proportionate to those companies'companies’ involvement at the site, while Entergy Arkansas and Entergy New Orleans
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likely will pay de minimis amounts. Current estimates, although preliminary and variable depending on the level of third-party cost contributions, indicate that Entergy'sEntergy’s total share of remediation costs likely will be less than $1in the range of $1.5 million to $2 million. The TCEQ approved an Agreed Administrative Order onagreed administrative order in September 20, 2006 that allows the implementation of a Remedial Investigation/Feasibility Study at the SESCO site; with the ultimate disposition being a remedial action to remove contaminants of concern. TCEQThis study was approved the Remedial Investigation Work Plan in May 2007 and field sampling began in July 2007.September 2012.
Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The EPA has notified Entergy Mississippi, Entergy Gulf States Louisiana, Entergy Texas, and Entergy New Orleans that the EPA believes those entities are PRPs concerning contamination of an area known as "Devil's“Devil’s Swamp Lake"Lake” near the Port of Baton Rouge, Louisiana. The area allegedly was contaminated by the operations of Rollins Environmental (LA), Inc, which operated a disposal facility to which many companies contributed waste. Documents provided by the EPA indicate that Entergy Louisiana may also be a PRP. Entergy continues to monitor this developing situation.
Entergy
In November 2010 a transformer at the Indian Point facility failed, resulting in a fire and the release of non-PCB oil to the ground surface. The fire was extinguished by the facility’s fire deluge system along with the site’s fire brigade. No injuries occurred due to the transformer failure or Entergy’s response. Non-PCB oil and deluge water were released into the facility’s discharge canal and the environment surrounding the transformer and discharge canal, including the Hudson River, as a result of the failure, fire,
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and fire suppression. As a result of this discharge of non-PCB oil, Entergy in March 2012 agreed to a settlement with the New York State Department of Environmental Conservation under which Entergy paid a civil penalty of $625,000, will pay another $600,000 to environmental benefit programs in the region, and a possible additional payment of $275,000 that is suspended contingent upon Entergy’s compliance with the other terms of the settlement. Entergy also paid $67,000 in natural resource damages and oversight costs.
Entergy uses legal and appropriate means to contest litigation threatened or filed against it, but certain states in which Entergy operates have proven to be unusually litigious environments. Judges and juries in Louisiana, Mississippi, and Texas have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. The litigation environment in these states poses a significant business risk to Entergy.
Ratepayer and Fuel Cost Recovery Lawsuits (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy New Orleans Fuel Adjustment Clause Litigation
In April 1999, a group of ratepayers filed a complaint against Entergy New Orleans, Entergy Corporation, Entergy Services, and Entergy Power in state court in Orleans Parish purportedly on behalf of all Entergy New Orleans ratepayers. The plaintiffs seek treble damages for alleged injuries arising from the defendants' alleged violations of Louisiana's antitrust laws in connection with certain costs passed on to ratepayers in Entergy New Orleans' fuel adjustment filings with the City Council. In particular, plaintiffs allege that Entergy New Orleans improperly included certain costs in the calculation of fuel charges and that Entergy New Orleans imprudently purchased high-cost fuel or energy from other Entergy affiliates. Plaintiffs allege that Entergy New Orleans and the other defendant Entergy companies conspired to make these purchases to the detriment of Entergy New Orleans' ratepayers and to the benefit of Entergy's shareholders, in violation of Louisiana's antitrust laws. Plaintiffs also seek to recover interest and attorneys' fees. Entergy filed exceptions to the plaintiffs' allegations, asserting, among other things, that jurisdiction over these issues rests with the City Council and the FERC. In March 2004, the plaintiffs supplemented and amended their petition. If necessary, at the appropriate time, Entergy will also raise its defenses to the antitrust claims. The suit in state court was stayed by stipulation of the parties and order of the court pending review of the decision by the City Council in the proceeding discussed in the next paragraph.
Plaintiffs also filed a corresponding complaint with the City Council in order to initiate a review by the City Council of the plaintiffs' allegations and to force restitution to ratepayers of all costs they allege were improperly and imprudently included in the fuel adjustment filings. Testimony was filed on behalf of the plaintiffs in this proceeding asserting, among other things, that Entergy New Orleans and other defendants have engaged in fuel procurement and power purchasing practices and included costs in Entergy New Orleans' fuel adjustment that could have resulted in Entergy New Orleans customers being overcharged by more than $100 million over a period of years. Hearings were held in February and March 2002. In February 2004, the City Council approved a resolution that resulted in a refund to customers of $11.3 million, including interest, during the months of June through September 2004. In May 2005 the Civil District Court for the Parish of Orleans affirmed the City Council resolution, finding no support for the plaintiffs' claim that the refund amount should be higher. In June 2005, the plaintiffs appealed the Civil District Court decision to the Louisiana Fourth Circuit Court of Appeal. On February 25, 2008, the Fourth Circuit Court of Appeal
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issued a decision affirming in part, and reversing in part, the Civil District Court's decision. Although the Fourth Circuit Court of Appeal did not reverse any of the substantive findings and conclusions of the City Council or the Civil District Court, the Fourth Circuit found that the amount of the refund was arbitrary and capricious and increased the amount of the refund to $34.3 million. Entergy New Orleans and the City Council filed with the Louisiana Supreme Court seeking, among other things, review and reversal of the Fourth Circuit decision. In April 2009 the Louisiana Supreme Court reversed the decision of the Louisiana Fourth Circuit Court of Appeal and reinstated the decision of the Civil District Court. In May 2009 the Louisiana Supreme Court denied the plaintiffs' request for rehearing. In January 2010 the plaintiffs filed a motion to lift the stay and to supplement and amend their state court petition.
In the Entergy New Orleans bankruptcy proceeding, the named plaintiffs in the Entergy New Orleans fuel clause lawsuit, together with the named plaintiffs in the Entergy New Orleans rate of return lawsuit, filed a Complaint for Declaratory Judgment asking the court to declare that Entergy New Orleans, Entergy Corporation, and Entergy Services are a single business enterprise, and, as such, are liable in solido with Entergy New Orleans for any claims asserted in the Entergy New Orleans fuel adjustment clause lawsuit and the Entergy New Orleans rate of return lawsuit, and, alternatively, that the automatic stay be lifted to permit the movants to pursue the same relief in state court. The bankruptcy court dismissed the action on April 26, 2006. The matter was appealed to the U.S. District Court for the Eastern District of Louisiana, and the district court affirmed the dismissal in October 2006, but on different grounds, concluding that the lawsuit was premature. In Entergy New Orleans' plan of reorganization that was confirmed by the bankruptcy court in May 2007, the plaintiffs' claims are treated as unimpaired "Litigation Claims," which will "ride through" the bankruptcy proceeding, with any legal, equitable and contractual rights to which the plaintiffs' Litigation Claim entitles the plaintiffs unaltered by the plan of reorganization.
Entergy New Orleans Rate of Return Lawsuit
In April 1998, a group of residential and business ratepayers filed a complaint against Entergy New Orleans in state court in Orleans Parish purportedly on behalf of all ratepayers in New Orleans. The plaintiffs allege that Entergy New Orleans overcharged ratepayers by at least $300 million since 1975 in violation of limits on Entergy New Orleans' rate of return that the plaintiffs allege were established by ordinances passed by the City Council in 1922. The plaintiffs seek, among other things, (i) a declaratory judgment that such franchise ordinances have been violated; and (ii) a remand to the City Council for the establishment of the amount of overcharges plus interest. Entergy New Orleans believes the lawsuit is without merit. Entergy New Orleans has charged only those rates authorized by the City Council in accordance with applicable law. In May 2000, a court of appeal granted Entergy New Orleans' exception to jurisdiction in the case and dismissed the proceeding. The Louisiana Supreme Court denied the plaintiffs' request for a writ of certiorari.
The plaintiffs then commenced a similar proceeding before the City Council. The plaintiffs and the advisors for the Council each filed their first round of testimony in January 2002. In their testimony, the plaintiffs allege that Entergy New Orleans earned in excess of the legally authorized rate of return during the period 1979 to 2000 and that Entergy New Orleans should be required to refund between $240 million and $825 million to its ratepayers. In the testimony submitted by the Council advisors, the advisors allege that Entergy New Orleans has not earned in excess of its authorized rate of return for the period at issue and that no refund is therefore warranted.
In December 2003, the Council advisors filed a motion in the City Council proceedings to bifurcate the hearing in this matter, such that the effect of the provision of the 1922 Ordinance in setting lawful rates would be considered first. Only if it is determined that this provision establishes a limitation would the remaining issues be reached. The motion to bifurcate was granted by the City Council in April 2004, and a hearing on the first part of the bifurcated proceeding was completed in June 2005. After the submission of briefs and oral argument in April 2006, the City Council dismissed with prejudice the plaintiffs' claims on multiple grounds. In May 2006, the plaintiffs appealed the City Council's decision, and the plaintiffs' appeal is currently pending in Civil District Court for the Parish of Orleans. Entergy New Orleans also appealed, separately, certain evidentiary rulings included in the City Council's decision. These matters were consolidated and oral argument on these appeals took place before the Civil District Court in August 2008.
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Additionally, in the Entergy New Orleans bankruptcy proceeding, the named plaintiffs in the Entergy New Orleans rate of return lawsuit, together with the named plaintiffs in the Entergy New Orleans fuel adjustment clause lawsuit, filed a Complaint for Declaratory Judgment asking the court to declare that Entergy New Orleans, Entergy Corporation, and Entergy Services are a single business enterprise, and, as such, are liable in solido with Entergy New Orleans for any claims asserted in the Entergy New Orleans rate of return lawsuit and the Entergy New Orleans fuel adjustment clause lawsuit, and, alternatively, that the automatic stay be lifted to permit the movants to pursue the same relief in state court. The bankruptcy court dismissed the action on April 26, 2006. The matter was appealed to the U.S. District Court for the Eastern District of Louisiana, and the district court affirmed the dismissal in October 2006, but on different grounds, concluding that the lawsuit was premature. In Entergy New Orleans' plan of reorganization that was confirmed by the bankruptcy court in May 2007, the plaintiffs' claims are treated as unimpaired "Litigation Claims," which will "ride through" the bankruptcy proceeding, with any legal, equitable and contractual rights to which the plaintiffs' Litigation Claim entitles the plaintiffs unaltered by the plan of reorganization.
Texas Power Price Lawsuit
In August 2003, a lawsuit was filed in the district court of Chambers County, Texas by Texas residents on behalf of a purported class apparently of the Texas retail customers of Entergy Gulf States, Inc. who were billed and paid for electric power from January 1, 1994 to the present. The named defendants include Entergy Corporation, Entergy Services, Entergy Power, Entergy Power Marketing Corp., and Entergy Arkansas. Entergy Gulf States, Inc. was not a named defendant, but iswas alleged to be a co-conspirator. The court granted the request of Entergy Gulf States, Inc. to intervene in the lawsuit to protect its interests.
Plaintiffs allege that the defendants implemented a "price“price gouging accounting scheme"scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting and/or reselling to off-system utilities less expensive power offered and/or purchased from off-system suppliers and/or generated by the Entergy system.suppliers. In particular, plaintiffs allege that the defendants manipulated and continue to manipulate the dispatch of generation so that power is purchased from affiliated expensive resources instead of buying cheaper off-system power.
Plaintiffs stated in their pleadings that customers in Texas were charged at least $57 million above prevailing market prices for power. Plaintiffs seek actual, consequential and exemplary damages, costs and attorneys'attorneys’ fees, and disgorgement of profits. The plaintiffs'plaintiffs’ experts have tendered a report calculating damages in a large range, from $153 million to $972 million in present value, under various scenarios. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs'plaintiffs’ expert reports.
The case is pending in state district court, and in March 2012 the court has not set a date forfound that the case met the requirements to be maintained as a class certification hearing.action under Texas law. On April 30, 2012, the court entered an order certifying the class. The defendants have appealed the order to the Texas Court of Appeals – First District. The appeal is pending and proceedings in district court are stayed until the appeal is resolved.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigationcomplaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. OnIn December 29, 2008 the defendant Entergy companies filed to removeremoved the attorney general'sgeneral’s suit to U.S. District Court (the forumin Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
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Entergy believes is appropriate to resolve the types of federal issues raised in the suit), where it is currently pending,Corporation, Utility operating companies, and additionallySystem Energy
The defendant Entergy companies answered the complaint and filed a counter-claimcounterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The Mississippi attorney general has filed a pleading seeking to remand the matter to state court. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general'sgeneral’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
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Fiber Optic Cable Litigation (Entergy Corporation and Entergy Louisiana)
Several property owners have filed a class action suit against Entergy Louisiana, Entergy Services, ETHC,Entergy Technology Holding Company, and Entergy Technology Company in state court in St. James Parish, Louisiana purportedly on behalf of all property owners in Louisiana who have conveyed easements to the defendants. The lawsuit alleges that Entergy installed fiber optic cable across the plaintiffs'plaintiffs’ property without obtaining appropriate easements. The plaintiffs seek damages equal to the fair market value of the surplus fiber optic cable capacity, including a share of the profits made through use of the fiber optic cables, and punitive damages. Entergy removed the case to federal court in New Orleans; however, the district court remanded the case back to state court. In February 2004 the state court entered an order certifying this matter as a class action. Entergy'sEntergy’s appeals of this ruling were denied. The parties have entered into a term sheet establishing basic terms for a settlement that must bewhich was approved by the court.court in March 2012. No appeal was taken from the court’s ruling approving the settlement and all claims have been submitted. The total exposure of the Entergy companies in this matter is $4.5 million. All funding of this exposure is from Entergy Technology Holding Company, Entergy Technology Company and Entergy Corporation. Entergy Services, Inc. and the Utility operating companies will not contribute to the settlement.
Asbestos Litigation (Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Numerous lawsuits have been filed in federal and state courts primarily in Texas and Louisiana, primarily by contractor employees who worked in the 1940-1980s timeframe, against Entergy Gulf States Louisiana and Entergy Texas, and to a lesser extent the other Utility operating companies, as premises owners of power plants, for damages caused by alleged exposure to asbestos. Many other defendants are named in these lawsuits as well. Currently, there are approximately 500400 lawsuits involving approximately 5,000 claimants. Management believes that adequate provisions have been established to cover any exposure. Additionally, negotiations continue with insurers to recover reimbursements. Management believes that loss exposure has been and will continue to be handled so that the ultimate resolution of these matters will not be material, in the aggregate, to the financial position or results of operation of the Utility operating companies.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The Registrant Subsidiaries and other Entergy subsidiaries are responding to various lawsuits in both state and federal courts and to other labor-related proceedings filed by current and former employees.employees, recognized bargaining representatives, and third parties not selected for open positions or providing services directly or indirectly to one or more of the Registrant Subsidiaries and other Entergy subsidiaries. Generally, the amount of damages being sought is not specified in these proceedings. These actions include, but are not limited to, allegations of wrongful employment actions; wage disputes and other claims under the Fair Labor Standards Act or its state counterparts; claims of race, gender, age, and disability discrimination; disputes arising under collective bargaining agreements; unfair labor practice proceedings and other administrative proceedings before the National Labor Relations Board;Board or concerning the National Labor Relations Act; claims of retaliation; and claims for or regarding benefits under various Entergy Corporation sponsoredCorporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these suitslawsuits and proceedings and deny liability to the claimants.
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Employees are an integral part of Entergy'sEntergy’s commitment to serving its customers. As of December 31, 2009,2012, Entergy subsidiaries employed 15,18114,625 people.
| Utility: | | |
| Entergy Arkansas | | 1,4731,372 |
| Entergy Gulf States Louisiana | | 840798 |
| Entergy Louisiana | | 1,005947 |
| Entergy Mississippi | | 797749 |
| Entergy New Orleans | | 368341 |
| Entergy Texas | | 727651 |
| System Energy | | - |
| Entergy Operations | | 2,9102,920 |
| Entergy Services | | 3,2343,043 |
| Entergy Nuclear Operations | | 3,7473,688 |
| Other subsidiaries | | 80116 |
| Total Entergy | | 15,18114,625 |
Approximately 5,5005,200 employees are represented by the International Brotherhood of Electrical Workers, Union, the Utility Workers Union of America, the International Brotherhood of Teamsters, Union, and the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.
Entergy electronically files reports with the SEC, including annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxies, and amendments to such reports. The public may read and copy any materials that Entergy files with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains an internet site that contains reports, proxy and information statements, and other information regarding registrants that file electronically with the SEC at http://www.sec.gov.
Entergy uses its website, http://www.entergy.com, as a routine channel for distribution of important information, including news releases, analyst presentations and financial information. Filings made with the SEC are posted and available without charge on Entergy's website as soon as reasonably practicable after they are electronically filed with, or furnished to, the SEC. These filings include our annual and quarterly reports on Forms 10-K and 10-Q (including related filings in XBRL format) and current reports on Form 8-K; our proxy statements; and any amendments to those reports or statements. All such postings and filings are available on Entergy's Investor Relations website free of charge. Entergy is providing the address to its Internet site solely for the information of investors and does not intend the address to be an active link. The contents of the website are not incorporated into this report.
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RISK FACTORS
Investors should review carefully the following risk factors and the other information in this Form 10-K. The risks that Entergy faces are not limited to those in this section. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect Entergy'sEntergy’s financial condition, results of operations, and liquidity. See "FORWARD-LOOKING INFORMATION."“FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The terms and conditions of service, including electric and gas rates, of the Utility operating companies and System Energy are determined through regulatory approval proceedings that are lengthy and subject to appeal that could result in delays in effecting rate changes and uncertainty as to ultimate results.
The rates that the Utility operating companies and System Energy charge reflect their capital expenditures, operations and maintenance charges, allowed rates of return, financing costs, and related costs of service. These rates significantly influence the financial condition, results of operations, and liquidity of Entergy and each of the Utility operating companies and System Energy. These rates are determined in regulatory proceedings and are subject to periodic regulatory review and adjustment.
In addition, regulators can initiate proceedings to investigate the prudence of costs in the Utility operating companies'companies’ base rates and examine, among other things, the reasonableness or prudence of the companies'companies’ operation and maintenance practices, level of expenditures (including storm costs)costs and costs associated with capital projects), allowed rates of return and appropriate rate base, proposed resource acquisitions, and previously incurred capital expenditures. The regulators can disallow costs found not to have been prudently incurred or found not to have been incurred in compliance with applicable tariffs, creating some risk to the ultimate recovery of those costs. Regulatory proceedings relating to rates and other matters typically involve multiple parties seeking to limit or reduce rates. The proceedings generally have long timelines, are primarily based on historical costs, and may or may not be limited by statute, which could cause the Utility operating companies and System Energy to experience regulatory lag in recovering such costs through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings. Entergy Mississippi currently obtains recovery under a formula rate plan. In the event that this formula rate plan is ever terminated, Entergy Mississippi would at that time operate exclusively in the more traditional rate case environment.
In January 2013, Entergy Gulf States Louisiana’s and Entergy Louisiana’s current formula rate plans expired, and each company filed full rate cases in February 2013. As part of the rate cases that Entergy Louisiana and Entergy Gulf States Louisiana filed, each company requested that the LPSC approve new formula rate plans. Entergy Louisiana and Entergy Gulf States Louisiana cannot predict the outcome of this request. In addition, Entergy New Orleans’ formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility, which is currently expected in the first quarter of 2015.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, which could result in more frequent rate cases and requests for, and the continuation of, cost recovery mechanisms. For information regarding rate case proceedings and formula rate plans applicable to certain of the Utility operating companies, see Note 2 to the financial statements.
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The Utility operating companies recover fuel and purchased power costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel and purchased power costs from their customers through rate mechanisms subject to periodic regulatory review and adjustment. Because regulatory review can result in the disallowance of incurred costs found not to have been prudently incurred with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators can initiate proceedings to investigate the continued usage or the adequacy and operation of the fuel and purchased power recovery clauses of the Utility operating companies.
The Utility operating companies'companies’ cash flows can be negatively affected by the time delays between when gas, power, or other commodities are purchased and the ultimate recovery from customers of the costs in rates. On occasion, when the level of incurred costs for fuel and purchased power rises very dramatically, some of the Utility operating companies may agree to defer recovery of a portion of that period'speriod’s fuel and purchased power costs for recovery at a later date, which could increase the near-term working capital and borrowing requirements of those companies. For a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power recovery, see Note 2 to the financial statements.
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As a result of a challenge by the LPSC, the manner in which the Utility operating companies have traditionally shared the costs associated with coordinated planning, construction, and operation of generating resources and bulk transmission facilities has been changed by the FERC, which willcould require adjustment of retail and wholesale rates in the jurisdictions where the Utility operating companies provide service and has introduced additional uncertainty in the ratemaking process.
The Utility operating companies historically have engaged in the coordinated planning, construction, and operation of generating resources and bulk transmission facilities under the terms of the System Agreement, which is a rate schedule that has been approved by the FERC. In 2005 the FERC issued a decision requiring changes to the cost allocation methodology used in that rate schedule.
In 2007 through 2009,2012, payments were made by Entergy Arkansas to certain of the Utility operating companies. Although actual payments/receipts for 2010, basedcompanies in compliance with the 2005 FERC decision on calendar year 2009 production costs, will not be calculated untilthe cost allocation methodology. There have been challenges to the level and timing of payments made by Entergy Arkansas under the FERC’s decision and the prudence of the Utility operating companies have filed their FERC Form 1s, preliminary estimates indicate that Entergy Arkansas will be requiredcompanies’ production costs. The ability to make payments of approximately $70 millionrecover in 2010. Entergy's management believes thatrates any changes into the cost allocation of production costs resulting from the FERC's decisionchallenges, and related retail proceedings should result in similar rate changes for retail customers. The timing of such recovery, of these costs in rates, however,could be uncertain and could be the subject of additional regulatory and other proceedings. For information regarding these and other proceedings associated with the System Agreement, as well as additional information regarding the System Agreement itself, see Note 2 to financial statements, System Agreement Cost Equalization Proceedings. The outcome and timing of this FERC proceeding and resulting recovery and impact on rates cannot be predicted at this time.
InThere is uncertainty as to the timing or form of any successor arrangement to the System Agreement and the effect of such arrangement (or absence thereof) on Entergy and the Utility operating companies.
Based upon the effect of the FERC decision described in the preceding risk factor, in December 2005, Entergy Arkansas provided notice of its intent to terminate its participation in the System Agreement. In November 2007, Entergy Mississippi provided its notice to terminate its participation in the System Agreement. Each notice of termination is effective ninety-six (96) months from the date of notice (December 2013 for Entergy Arkansas and November 2015 for Entergy Mississippi) or such earlier date as authorized by the FERC. The FERC accepted the notices in November 2009;2009, and the U.S. Court of Appeals for the D.C. Circuit has denied appeals of FERC’s decision filed by the LPSC and City Council. In January 2013 the LPSC and City Council filed a petition for a writ of certiorari with the U.S. Supreme Court.
The Utility operating companies have requested rehearingconcluded that joining the MISO RTO is in the best interest of all stakeholders and have filed applications with their retail regulators seeking to join the MISO RTO by December 2013. To that order. Entergy cannot predictend, the timing or the form of any successor arrangementUtility operating companies have received orders from their respective retail regulators granting their respective requests to join MISO, subject to certain conditions. The Utility operating companies have also filed with FERC amendments to the System Agreement under
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Section 205 of the Federal Power Act. The amendments allocate certain charges and credits from MISO settlement statements to the extent one isUtility operating companies that participate in the System Agreement and address Entergy Arkansas’s withdrawal from the System Agreement. Certain FERC filings related to the rates, terms, and conditions of integrating the Utility operating companies into MISO are planned for early-mid 2013. Entergy cannot predict when or whether the Utility operating companies will satisfy the conditions of the retail regulatory orders or obtain FERC approvals related to the rates, terms, and conditions under which the Utility operating companies will join MISO or when the Utility operating companies’ generation and transmission systems can be fully integrated into the MISO RTO. Moreover, if the operating companies are not successful in joining MISO, alternative or additional arrangements will need to be implemented orto allow Entergy Arkansas, and eventually Entergy Mississippi, to operate independent of the System Agreement after these companies terminate their participation in the System Agreement, and the effect such a successor arrangementarrangements (or the absence thereof) will have on Entergy or the Utility operating companies.companies is uncertain.
The LPSC, APSC, MPSC and the AEEC have appealed the 2005 FERC decision to the Court of Appeals for the D.C. Circuit. Entergy and the City of New Orleans intervened in the various appeals. The D.C. Circuit issued its decision in April 2008. The D.C. Circuit affirmed the FERC's decision in most respects, but remanded the case toFor further information regarding the FERC for furtherand APSC proceedings and reconsideration of its conclusion that it was prohibited from ordering refunds and its determinationrelating to implement the bandwidth remedy commencing with calendar year 2006 production costs (with the first payments/receipts commencing in June 2007), rather than commencing the remedy on June 1, 2005. The D.C. Circuit concluded the FERC had failed to offer a reasoned explanation regarding these issues. The proceeding is pending at the FERC. For information regarding these and other proceedings associated with the System Agreement as well as additional information regarding the System Agreement itself,and Entergy’s proposal to join MISO, see the "“Rate, Cost-recovery, and Other Regulation – Federal Regulation - – System Agreement Proceedings" section” and “ – Entergy’s Proposal to Join MISO” sections of Management'sManagement’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.
The arrangement for the operation of the Utility operating companies’ transmission system faces regulatory and operating challenges and uncertainty in connection with the Utility operating companies’ proposal to move to the MISO RTO.
In 2000 the FERC issued an order encouraging utilities to voluntarily place their transmission facilities under the control of an independent RTO. In November 2006 the Utility operating companies installed the Southwest Power Pool (SPP), a regional transmission organization, as their Independent Coordinator of Transmission (ICT) with responsibility for certain transmission tariff functions, including granting or denying transmission service, administering OASIS, evaluating all transmission requests, and serving as the reliability coordinator. The initial term of the ICT was for four years and in November 2010 the FERC approved an extension of the ICT arrangement for two years, or until November 2012. In its order issued in March 2009 pertaining to a requested modification regarding the weekly procurement process (WPP) through the ICT arrangement, the FERC imposed conditions related to the ICT arrangement and indicated it wanted an evaluation of the success of the ICT arrangement and transmission access on the Entergy transmission system. In compliance with the FERC’s March 2009 order, the Utility operating companies filed with the FERC a process for evaluating the modification or replacement of the current ICT arrangement. An Entergy Regional State Committee (E-RSC), comprised of one representative from each of the Registrant Subsidiaries. See "FuelUtility operating companies’ retail regulators has been formed and, purchased power cost recovery, in concert with the FERC, retained an independent entity to conduct a cost-benefit analysis of comparing the ICT arrangement to a proposal under which Entergy Texas," in Note 2would join the SPP RTO. The scope of the study was later expanded to consider Entergy joining the financial statementsMISO RTO as another alternative. On April 25, 2011, Entergy announced that each of the Utility operating companies propose joining the MISO RTO. In May 2011 the Utility operating companies submitted to each of their respective retail regulators the cost-benefit analysis comparing the option of continuing with the ICT arrangement to joining the SPP RTO or the MISO RTO. The Utility operating companies have received orders from their respective retail regulators granting their respective requests to join MISO, subject to certain conditions. The target implementation date for discussion of a PUCT decision that Entergy Texasjoining the MISO RTO is currently challengingDecember 2013. For further information regarding its rough production cost equalization receipts that could result in $18.6 million of trapped costs between Entergy's Texas and Louisiana jurisdictions. The outcome and timing of the FERC and these other proceedings related to the ICT and appealsMISO, see “Rate, Cost-recovery, and Other Regulation - Federal Regulation - Independent Coordinator of Transmission” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.
There is uncertainty as to whether the conditions of the retail regulators’ orders granting the Utility operating companies’ requests to transfer control of their transmission assets to MISO will be satisfied in a timely manner and, if the conditions are satisfied, the nature and effect of any operational challenges the Utility operating companies might face in connection with integration into the MISO RTO. For the period of time prior to integration of all of the Utility operating companies into the MISO RTO or in
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the event all necessary approvals to participate in the MISO RTO are not obtained in a timely manner, the Utility operating companies have received the necessary regulatory approvals to change provider of ICT services from SPP to MISO. MISO began providing ICT services to the Utility operating companies on December 1, 2012 and is under contract to continue to provide those services until December 31, 2014, in the event that some or all of the Utility operating companies are not integrated into MISO by December 2013. To the extent some or all of the Utility operating companies are not integrated into MISO by December 2014, an extension of the current ICT arrangement or the establishment of a similar arrangement with another qualified entity may be required. The outcome of any effort to negotiate an extension of the current arrangement or to make alternative arrangements cannot be predicted at this time.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
A delay or failure in recovering amounts for storm restoration costs incurred as a result of severe weather could have material adverse effects on Entergy and those Utility operating companies affected by severe weather.
Entergy'sEntergy’s and its Utility operating companies'companies’ results of operations, liquidity, and financial condition can be materially adversely affected by the destructive effects of severe weather. Severe weather can also result in significant outages for the customers of the Utility operating companies and, therefore, reduced revenues for the Utility operating companies during the period of the outages. A delay or failure in recovering amounts for storm restoration costs incurred or revenues lost as a result of severe weather could have a material adverse effect on Entergy and those Utility operating companies affected by severe weather.
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Nuclear Operating and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially adversely affect Entergy'sEntergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies',companies, System Energy'sEnergy, and the Non-Utility Nuclear subsidiaries' results of operations.Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating costs, as well as non-fixed costs associated with plant operating conditions and issues.costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors. LowerFor the Utility operating companies that own nuclear plants, lower capacity factors can increase operatingproduction costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossil or hydroelectric facilities or purchase additional energy in the spot or forward markets in order to satisfy their supply needs. For the Entergy Wholesale Commodities nuclear plants, lower capacity factors directly affect revenues and cash flow from operations. Although most of the Non-Utility NuclearEntergy Wholesale Commodities nuclear forward sales are on a pure unit-contingent basis, which depends on the availability of the asset, some of the unit-contingent contracts guarantee a specificspecified minimum capacity factor. Non-Utility Nuclear forward sales can also be on a Firm LD basis. In the event these plants were operating below the guaranteed capacity factors, the unit-contingent contracts carrying damage provisionsEntergy would be subject the Entergy System to price risk for the undelivered power. Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk, a portion of which may be capped through the use of risk management products, if capacity factors decrease.
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Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities’ nuclear plant owners periodically shutdownshut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such fuelrefueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy'sEntergy’s and their results of operations, financial condition, and liquidity could be materially adversely affected.
Outages at nuclear power plants to replenish fuel require the plant to be "turned“turned off."” Refueling outages generally are planned to occur once every 18 to 24 months and have historically averagedaverage approximately 30 days in duration. Plant maintenance and upgrades are often scheduled during such planned outages. When refueling outages last longer than anticipated or a plant experiences unplanned outages, capacity factors decrease and maintenance costs may increase. The Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities’ nuclear plants may face lower margins due to higher costs and lower energy sales for unit-contingent power supply contracts or potentially higher energy replacement costs for unit-contingent contracts with capacity guarantees that are not met due to extended or unplanned outages.
Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication), and their inabilitythe risk of being unable to effectively manage these risks by purchasing from a diversified mix of sellers located in a diversified mix of countries could materially adversely affect Entergy'sEntergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy'sEntergy’s nuclear units have a diversified portfolio of contracts and inventory that provides substantially adequate nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable prices through most of 2010. It will be necessary for Entergy to enter into additional arrangements to acquire nuclear fuel and related services beyond 2010. Entergy's2013. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the creditworthiness and performance reliability of uranium miners, as well as upon the structure of Entergy's contracts for the purchase of nuclear fuel. For example, some of the supply under Entergy's contracts for nuclear fuel is effectively on a "mine-contingent" basis, which means that if applicable mines are unable to supply sufficient uranium, Entergy may be required to purchase some nuclear fuel from another supplier. Thereminers. While there are a number of possible alternate suppliers that may be accessed to mitigate such an event, including potentially drawing upon Entergy's own inventory intended for later generation periods depending upon its risk management strategy at that time, althoughany supplier performance failure, the pricing of any such alternate uranium supply from the market will be dependent upon the market for uranium supply at that time. The marketEntergy also may draw upon its own inventory intended for uranium supply became extremely limited in 2006 and 2007, but this supply shortfall was substantially eliminated in 2008 and 2009. Market prices for uranium concentrates rose from about $7 per pound in December 2000 to a 2007 range of $70 to $135 per pound. In 2008, however, market prices for uranium concentrates ranged from $45 to $90 per pound and from January 1, 2009 through December 31, 2009 ranged from $40 to $55 per pound. The recent higher nuclear fuel market prices of 2006-2009 compared to the 2000-2005 period affect the U.S. nuclear utility industry, including Entergy, first in cash flow requirements for fuel acquisition, and then, some time later in nuclear fuel expenses. For example, for a nuclear fleet the size of Entergy's, the current market value of annual enriched
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
uranium requirements has increased by several hundred million dollars compared to about five years ago. As nuclear fuel installed in the core in nuclear power plants is replaced fractionally over an approximate five-year period, nuclear fuel expense is beginning to, and will eventually with a time lag, reflect current market prices and can be expected to increase from the previously reported industry levels of about 0.5 cents per kWh to closer to 1.0 cent per kWh.generation periods, depending upon its risk management strategy at that time. Entergy buys uranium from a diversified mix of sellers located in a diversified mix of countries, and from time to time purchases from nearly all qualified reliable major market participants worldwide that sell into the U.S. Entergy'sMarket prices for nuclear fuel have been extremely volatile from time to time in the past. Although Entergy’s nuclear fuel contract portfolio has providedprovides a degree of price hedging against market risks for several years, costs for nuclear fuel in the full extent offuture cannot be predicted with certainty due to normal inherent market prices through 2010, but market trends will eventuallyuncertainties, and price increases could materially affect the costs of all nuclear plant operators. Entergy is dependent on the continued performance by suppliers of their obligations under their long-term agreementsliquidity, financial condition, and Entergy’s ability to manage these risks by purchasing uranium from a diversified mix of sellers located in a diversified mix of countries. Entergy’s financial results could be materially adversely affected if Entergy is unable to successfully manage these risks and any one major supplier fails to fulfill its contractual obligations and Entergy is unable to find other suppliers that can perform under terms that allow Entergy to achieve the same level of profitability. As a result of the failure of a major supplier to meet its contractual obligations or Entergy’s ability to manage such a risk, Entergy may face higher costs to secure other suppliers, which may have a material adverse effect on the results of operations financial condition and liquidityof certain of the Utility operating companies, System Energy, and the Non-Utility Nuclear subsidiaries.Entergy Wholesale Commodities.
Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesthe Entergy Wholesale Commodities business face the risk that the Nuclear Regulatory CommissionNRC will change or modify its regulations or suspend or revoke their licenses, which could materially adversely affect Entergy's and their results of operations, financial condition, and liquidity.
Under the Atomic Energy Act and Energy Reorganization Act, the NRC regulates the operation of nuclear power plants. The NRC may modify, suspend, or revoke licenses, shut down a nuclear facility and impose civil penalties for failure to comply with the Atomic Energy Act, related regulations, or the terms of the licenses for nuclear facilities. A change in the Atomic Energy Act, other applicable statutes, or the applicable regulations or licenses may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially adversely affect the results of operations, liquidity, or financial condition of Entergy (through its ownership of the Non-Utility Nuclear subsidiaries)Entergy Wholesale Commodities), its Utility operating companies, or System Energy or the Non-Utility Nuclear subsidiaries.Energy. Events at nuclear plants owned by others, as well as those owned by one of these companies, may cause the NRC to initiate such actions. As a result, if an incident were to occur at any nuclear generating unit, –whetherwhether an Entergy nuclear generating unit or not, - it could materially adversely affect the financial condition, results of operations, and liquidity of Entergy, certain of the Utility operating companies, System Energy, or Entergy Wholesale Commodities. For example, the Non-Utility Nuclear subsidiaries.
A failureearthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing three orders effective on March 12, 2012 requiring U.S. nuclear operators, including Entergy, to obtain renewed licenses for the continued operation ofundertake plant modifications or perform additional analyses that will, among other things, result in increased operating costs associated with operating Entergy’s nuclear power plants, some of which could have a material adverse effect on Entergy's operations and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.
The license renewal and related processes for Entergy's nuclear power plants has been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The operating licenses for Vermont Yankee, Pilgrim, Indian Point 2 and Indian Point 3 expire between 2012 and 2015. Various parties have expressed opposition to the pending license renewal applications. There is an ongoing proceeding before the Atomic Safety and Licensing Board of the NRC and contentions have been admitted for litigation regarding the Indian Point license renewals. The Atomic Safety and Licensing Board has completed its proceedings regardingmaterial.
Part I Item 1A & 1B
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Vermont Yankee, but the New England Coalition filed a petition for NRC review of the Atomic Safety Licensing Board’s decision on July 23, 2009. Finally, with respect to the Pilgrim license renewal, the NRC has issued decisions resolving most of the issues that were previously on appeal, but the NRC has asked for further briefing regarding one final issue, which could later be referred back for further proceedings before the Atomic Safety and Licensing Board. In addition, a group of environmental and civic organizations has filed a petition with the NRC seeking a suspension of the currently pending license renewal proceedings for Indian Point, Pilgrim and Vermont Yankee.
In relation to Indian Point 2 and Indian Point 3, the New York Department of Environmental Conservation has taken the position that Indian Point must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. Indian Point also must obtain a Coastal Zone Management Act consistency determination from the New York Department of State prior to getting its renewed license.
In addition to the NRC license renewal process with respect to Vermont Yankee, under Vermont law the Vermont Public Service Board will need to amend the certificate of public good held by Entergy Vermont Yankee, LLC and Entergy Nuclear Operations, Inc., which also requires Vermont legislative approval, and the Vermont Public Service Board and the Vermont legislature must approve and the Vermont Public Service Board must issue a certificate of public good for the continued operation of Vermont Yankee and storing of spent fuel generated in Vermont after March 21, 2012. An application has been filed with the Vermont Public Service Board (as required by Vermont law) for approval of continued operation and storage of spent nuclear fuel generated after that date. During its 2009 session, which concluded in May, several committees of the Vermont General Assembly held hearings on Vermont Yankee, but no bill or resolution was introduced for approval of continued operation and storage of spent nuclear fuel generated after March 21, 2012. In January 2010, the Governor of the State of Vermont issued a statement indicating he would not ask the Vermont General Assembly to consider the Vermont Yankee license renewal during its 2010 session, based on the discovery of tritium leakage from Vermont Yankee, concerns about miscommunication by Entergy Nuclear Vermont Yankee and Entergy Nuclear Operations related to underground piping at Vermont Yankee carrying radionuclides, and other issues including decommissioning. Notwithstanding the Governor's position, on February 24, 2010, a bill to approve the continued operation of Vermont Yankee was advanced to a vote by the Vermont Senate leadership and defeated by a margin of 26 to 4. This vote does not preclude the Vermont Senate from voting again on a similar bill in the future.
If the NRC does not renew the operating licenses for one or more of Entergy's nuclear power plants, or the states in which Entergy’s nuclear power plants are located do not otherwise take the necessary actions for the continued operation of these plants, to the extent applicable, Entergy’s results of operations could be materially adversely affected by loss of revenue associated with the plant or plants, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal.
Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their aging nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially adversely affect Entergy'sEntergy’s and their results of operations, financial condition, and liquidity.
The nuclear generating units owned by certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclearthe Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require significantmore capital expenditures to keep each of these nuclear power plants operating efficiently. This equipment is also likely to require periodic upgrading and improvement. Any unexpected failure, including failure associated with breakdowns, forced outages, or any unanticipated capital expenditures, could result in reduced profitability. Operations at any of the nuclear generating units owned and operated by Entergy'sEntergy’s subsidiaries could degrade to the point where the affected unit needs to be shut down or operated at less than full capacity. If this were to happen, identifying and correcting the causes may require significant time and expense. A decision may be made to close a unit rather than incur the expense of restarting it or returning the unit to full capacity. For the Non-Utility Nuclear subsidiaries,Entergy Wholesale Commodities, this could result in lost revenue and increased fuel and purchased power expense to meet supply commitments and penalties for failure to perform under their contracts with customers. Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy'sEntergy’s nuclear power plants that may need to be replaced or refurbished. This dependence on a reduced number of suppliers could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the Non-Utility Nuclear subsidiaries,owners of the Entergy Wholesale Commodities nuclear power plants, as well as the costs of and their ability to fully decommission their nuclear power plants, could be significantly affected by the timing of the opening of a spent nuclear fuel storage facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy and the Non-Utility Nuclear subsidiariesowners of the Entergy Wholesale Commodities nuclear plants incur costs on an annuala periodic basis for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the storage of spent nuclear fuel, such as the one proposed for Yucca Mountain, Nevada, or any interim storage facility, and the timing of such facility opening, will significantly affect the costs associated with storage of spent nuclear fuel. For example, while the DOE is required by law to proceed with the licensing of Yucca Mountain and, after the license is granted by the NRC, to construct the repository and commence the receipt of spent fuel, the Obama administration has cut the budget forexpressed its intention and taken specific steps to discontinue the Yucca Mountain project and has made various statements that Yucca Mountain will not be the solution forstudy a new spent fuel storage.strategy. These actions are likely tomay prolong the time before spent fuel is removed from Entergy’s plant sites. Because the DOE has not accomplished its objectives, it is in non-compliance with the Nuclear Waste Policy Act of 1982 and has breached its spent fuel disposal contracts.contracts, and Entergy has sued the DOE for such breach. Furthermore, Entergy is uncertain as to when the DOE plans to commence acceptance of spent fuel from its facilities for storage or disposal. As a result, continuing future expenditures will be required to increase spent fuel storage capacity at itsthe companies’ nuclear sites. The costs of on-site storage are also affected by regulatory requirements for such storage and will be subject to the costs of transportation to a permanent storage facility.storage. In addition, the availability of a repository or other off-site storage facility for spent nuclear fuel may affect the ability to fully decommission the nuclear units and the costs relating to decommissioning. For further information regarding spent fuel storage, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs – Spent Fuel Disposal” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy.
Certain of the Utility operating companies, System Energy, and Entergy's Non-Utility Nuclear subsidiariesthe Entergy Wholesale Commodities nuclear plant owners may be required to pay substantial retrospective premiums imposed under the Price-Anderson Act in the event of a nuclear incident, and losses not covered by insurance could have a material adverse effect on Entergy'sEntergy’s and their results of operations, financial condition, or liquidity.
Accidents and other unforeseen problems at nuclear power plants have occurred both in the United States and elsewhere. The consequences of an accident can be severe and include personal injury, loss of life and property damage. The Price-Anderson Act limits each reactor owner'sowner’s public liability (off-site) for a single nuclear incident to the payment of retrospective premiums into a secondary insurance pool of up to approximately $117.5 million per reactor. With 104 reactors currently participating, this translates to a total public liability cap of approximately $12.2 billion per incident. The limit is subject to
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
change to account for the effects of inflation, a change in the primary limit of insurance coverage, and changes in the number of licensed reactors. As required by the Price-Anderson Act, the Utility operating companies, System Energy, and Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers (currently $375 million for each operating site). Claims for any nuclear incident exceeding that amount are covered under the retrospective premiums paid into the secondary insurance pool. As a result, in the event of a nuclear incident that causes damages (off-site) in excess of the $375 million in primary insurance coverage, each owner of a nuclear plant reactor, including Entergy'sEntergy’s Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities plant owners, regardless of fault or proximity to the incident, will be required to pay a retrospective premium, equal to its proportionate share of the loss in excess of the $375 million primary level, up to a maximum of $117.5 million per reactor per incident (Entergy's(Entergy’s maximum total contingent obligation per incident is $1.3 billion). The retrospective premium payment is currently limited to $17.5 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $117.5 million cap. Nuclear accident damage
NEIL is a utility industry mutual insurance company, owned by its members. All member plants could be subject to on-site facilities is covered by Nuclear Electric Insurance Limitedassessments (retrospective premium of up to 10 times current annual premium for all policies) should the limitssurplus (reserve) be significantly depleted due to insured losses. As of April 1, 2012, the primarymaximum assessment amounts total $81.4 million for the Utility plants and excess property policies in force at$93.4 million for the time ofEntergy Wholesale Commodities plants. Retrospective Premium Insurance available through NEIL’s reinsurance treaty can cover the accident. potential assessments. The Entergy Wholesale Commodities plants currently maintain the Retrospective Premium Insurance to cover this potential assessment.
As an owner of nuclear power plants, Entergy participates in these mandatory industry self-insurance programs and could be liable to fund claims should a plant owned by a different company experience a major event. Any resulting liability from a nuclear accident may exceed any of the Utility operating companies', System Energy's, or the Non-Utility Nuclear subsidiaries'applicable primary insurance coverage and require contribution of additional funds through the industry-wide program that could significantly affect the results of operations, financial condition, or liquidity of Entergy, certain of the Utility operating companies, System Energy, or the Non-Utility NuclearEntergy Wholesale Commodities subsidiaries.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market performance and other changes may decrease the value of assets in the decommissioning trusts, which then could require significant additional funding.
Owners of nuclear generating plants have an obligation to decommission those plants. Certain of the Utility operating companies, System Energy, and owners of the Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities nuclear power plants maintain decommissioning trust funds for this purpose. Certain of the Utility operating companies collect funds from their customers, which are deposited into the trusts covering the units operated for or on behalf of those companies. Those rate collections are based upon operating license lives as well as estimated trust fund earnings and decommissioning costs. In connection with the acquisition of certain nuclear plants, the Entergy Non-Utility Nuclear subsidiariesWholesale Commodities plant owners also acquired decommissioning trust funds that are funded in accordance with NRC regulations. Assets in these trust funds are subject to market fluctuations, will yield uncertain returns that may fall below projected return rates, and may result in losses resulting from the recognition of impairments of the value of certain securities held in these trust funds. As part of the Pilgrim, Indian Point 1 and 2, Vermont Yankee, and Palisades/Big Rock Point purchases, the former owners transferred decommissioning trust funds, along with the liability to decommission the plants, to Entergy.the respective Entergy Wholesale Commodities nuclear power plant owners. In addition, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but has the right to require the respective Entergy
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigns the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner may contract with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the transferred funds mentioned above. As part of the Indian Point 1 and 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental ecommissioningdecommissioning trust fund. As part of the Palisades transaction, Non-Utility Nuclearthe Entergy Wholesale Commodities business assumed responsibility for spent fuel at the decommissioned Big Rock Point nuclear plant, which is located near Charlevoix, Michigan. Once the spent fuel is removed from the site, Non-Utility Nuclearthe Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning. Non-Utility NuclearThe Entergy Wholesale Commodities business expects to fund this activity from operating revenue, and Entergy is providing $5 million in credit support to provide financial assurance to the NRC for this obligation to the NRC.obligation.
In 2008, Entergy experienced declines in the market value of assets held in the trust funds for meeting its decommissioning funding assurance obligations for its plants. This decline adversely affected Entergy’s ability to demonstrate compliance with the NRC’s requirements for providing financial assurance for decommissioning funding for some of its plants. In June 2009, the NRC issued letters indicating that the NRC staff had concluded that there were shortfalls in the amount of decommissioning funding assurance provided for Indian Point 2, Vermont Yankee, Palisades, Waterford 3, and River Bend. The NRC staff subsequently conducted a telephone conference with Entergy on this issue and, in August 2009, Entergy submitted a plan for addressing the identified shortfalls. In its submittal, Entergy provided updated analyses to the NRC indicating that there was no current shortfall in the amounts of the required decommissioning funding assurance for Palisades and Indian Point 2, based upon the trust fund balances as of July 31, 2009 and an analysis of the costs that would be incurred if Entergy elected to use a sixty-year period of safe storage for decommissioning, as permitted by the NRC's rules. In December 2009 the NRC accepted the analyses regarding Palisades and Indian Point and, with respect to each plant, the NRC concluded that no further action was required. For Vermont Yankee, Entergy concluded that, when using the July 31, 2009 trust fund balance, and based on an analysis of the costs that would be incurred if Entergy elected to use a sixty year period of safe storage for decommissioning as permitted by the NRC’s rules, there was a shortfall of approximately $58 million,plants, which could be satisfied with a cash contribution to a decommissioning trust of approximately $51 million, or by using another financial assurance mechanism in the amount of approximately $58 million. In September 2009, the NRC requested further information regarding plans to address the shortfall in decommissioning funding assurance for Vermont Yankee, which Entergy provided in October 2009. Based on the trust fund balance as of September 30, 2009, the shortfall had decreased from $58 million to $40 million. This $40 million shortfall was satisfied with a $40 million guarantee from Entergy Corporation that was effective as of December 31, 2009. For Waterford 3 and River Bend, Entergy made the appropriate filings by December 31, 2009 with its retail regulators that request decommissioning funding from ratepayers to address the shortfalls identified by the NRC.
deficiencies have now been corrected. An early plant shutdown, poor investment results (depending on the performance of and volatility in the capital markets) or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities nuclear plant owners may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. For further information regarding nuclear decommissioning costs, see the "“Critical Accounting Estimates – Nuclear Decommissioning Costs"” section of Management'sManagement’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts. Part I Item 1A & 1B
Entergy Corporation,NRC regulations require certain minimum financial assurance requirements for meeting obligations to decommission nuclear power plants. Those financial assurance requirements may change from time to time, and certain changes may result in a material increase in the financial assurance required for decommissioning the Utility operating companies,companies’, System Energy’s and owners of the Entergy Wholesale Commodities’ nuclear power plants. Such changes could result in the need for additional contributions to decommissioning trusts, or the posting of parent guarantees, letters of credit, or other surety mechanisms. For further information regarding nuclear decommissioning costs, see the “Critical Accounting Estimates – Nuclear Decommissioning Costs” section of Management’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
New or existing safety concerns regarding operating nuclear power plants and nuclear fuel could lead to restrictions upon the operation of Entergy’s nuclear power plants.
New and existing concerns are being expressed in public forums about the safety of nuclear generating units and nuclear fuel, in particular in the northeastern United States, which is where five of the six units in the current fleet of Non-Utility Nuclear generating unitsEntergy Wholesale Commodities nuclear power plants are located. These concerns have led to, and are expected to continue to lead to, various proposals to Federal regulators and governing bodies in some localities where Entergy'sEntergy’s subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shut-downshutdown of nuclear units, denial of license renewal applications, municipalization of nuclear units, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning and operating nuclear generating units. Entergy vigorously responds to these concerns and proposals. If any of the existing proposals, or any proposals that may arise in the future with respect to legislative and regulatory changes, become effective, they could have a material adverse effect on Entergy'sEntergy’s results of operations, financial condition, and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale Commodities nuclear power plants could have a material effect on Entergy’s results of operations, financial condition, and liquidity and could lead to an increase in depreciation rates or an acceleration of the timing for the funding of decommissioning obligations.
The license renewal and related processes for the Entergy Wholesale Commodities nuclear power plants have been and may continue to be the subject of significant public debate and regulatory and legislative review and scrutiny at the federal and, in certain cases, state level. The operating licenses for Indian Point 2 and Indian Point 3 expire in September 2013 and December 2015, respectively. Because these plants filed timely license renewal applications, the NRC’s rules provide that these plants may continue to operate under their existing operating licenses until their renewal applications have been finally determined. Various parties have expressed opposition to renewal of these licenses. Renewal of the Indian Point licenses is the subject of ongoing proceedings before the Atomic Safety and Licensing Board (ASLB) of the NRC.
In relation to Indian Point 2 and Indian Point 3, the New York State Department of Environmental Conservation has taken the position that these plant owners must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. For the Indian Point plants, the Entergy Wholesale Commodities plant owners also must ensure that requirements of the Coastal Zone Management Act, which is administered in New York State primarily by the New York Department of State, are satisfied (to the extent required) prior to getting the renewed licenses. For further information regarding these environmental regulations see “Entergy Wholesale Commodities – Property –Nuclear Generating Stations” in Part I, Item 1.
The NRC operating license for Vermont Yankee was to expire in March 2012. In March 2011 the NRC renewed Vermont Yankee’s operating license for an additional 20 years, as a result of which the license now expires in 2032. Vermont Yankee also is operating under a Certificate of Public Good from the State of Vermont that expired in March 2012, but has an application pending before the Vermont Public Service Board for a new Certificate of Public Good for operation until March 2032, and continues to operate the plant pursuant to federal court order, the absence of any order to cease operation, and its position that Vermont’s law extends a license’s expiration date when a timely and sufficient renewal application has been filed. For additional discussion regarding the continued operation of the Vermont Yankee plant, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.
If the NRC finally denies the applications for the renewal of operating licenses for one or more of the Entergy Wholesale Commodities nuclear power plants, or a state in which any such nuclear power plant is located is able to prevent the continued operation of such plant, Entergy’s results of operations, financial condition, and liquidity could be materially affected by loss of revenue and cash flow associated with the plant or plants, potential impairments of the carrying value of the plants, increased depreciation rates, and an accelerated need for decommissioning funds, which could require additional funding. In addition, Entergy may incur increased operating costs depending on any conditions that may be imposed in connection with license renewal. For further discussion regarding the license renewal processes for the Entergy Wholesale Commodities’ nuclear power plants, see the “Entergy Wholesale Commodities – Property – Nuclear Generating Stations” section in Part I, Item 1.
The decommissioning trust fund assets for the nuclear power plants owned by Entergy's Non-Utility Nuclear subsidiariesEntergy Wholesale Commodities’ nuclear plant owners may not be adequate to meet decommissioning obligations if one or more of their nuclear power plants is retired earlier than the anticipated shutdown date or if current regulatory requirements change, which then could require additional funding.
Under Nuclear Regulatory CommissionNRC regulations, Entergy isEntergy’s nuclear subsidiaries are permitted to project the Nuclear Regulatory Commission-requiredNRC-required decommissioning amount based on an NRC formula or a Nuclear Regulatory Commission formulasite-specific estimate, and the amount in each of its Non-Utility Nuclearthe Entergy Wholesale Commodities nuclear power plant'splant’s decommissioning trusts.trusts combined with other decommissioning financial assurances in place. The projections are made based on the scheduled shutdownoperating license expiration date and the mid-point of the subsequent decommissioning process for each of these nuclear
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
power plants, with the earliest scheduled shutdown being Vermont Yankee in 2012.plants. As a result, if the projected amount of our decommissioning trusts exceeds the projected Nuclear Regulatory Commission-requiredNRC-required decommissioning amount, then its decommissioning obligations are considered to be funded in accordance with Nuclear Regulatory CommissionNRC regulations. In the event the Nuclear Regulatory Commission's formula doesprojected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, and funding is otherwise inadequate, or if the formula or site-specific estimate is changed to require increased funding, additional resources would be required. Furthermore, depending upon the level of funding available in the trust funds, the Nuclear Regulatory CommissionNRC may not permit the trust funds to be used to pay for related costs such as the management of spent nuclear fuel that are not included in the formula. The Nuclear Regulatory CommissionNRC may also require that separate financial assurances be provided as part of a plan for the provision of separate funding offor spent fuel management costs. In addition to Nuclear Regulatory CommissionNRC requirements, there are other decommissioning-related obligations for certain of the states in which Entergy's Non-Utility NuclearEntergy Wholesale Commodities nuclear power plants, are located have imposed other decommissioning related obligations, which Entergymanagement believes it will be able to satisfy.
With respect to the decommissioning trusts for Vermont Yankee, Indian Point 2 and Palisades, the total amount in each of those trusts as of December 31, 20092012 would not have been sufficient to initiate and complete the immediate near-term radiological decommissioning of the respective unit as of suchthe license termination date of each respective plant, but rather the funds would have been sufficient to place the unit in a condition of safe storage status pending future completion of decommissioning. For example, if an Entergy had decidedsubsidiary decides to shutdownshut down and immediately begin decommissioning one of those nuclear power plants on December 31, 2009,its license expiration date, its trust funds for the plant as of December 31, 2012 would have been insufficient and the applicable Entergy subsidiary would have been required to rely on other capital resources to fund the entireremainder of the radiological decommissioning obligations unless the completion of decommissioning could be deferred during some number of years of safe storage status. Thus, ifstatus (as is permitted by NRC regulations). If any Entergy subsidiary decides to shutdownshut down one of theseits nuclear power plants earlier than the scheduled shutdown date and conduct a prompt decommissioning, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations, which would require it to obtain funding from other sources.
Further, federal or state regulatory changes, including mandated increases in decommissioning funding or changes in the methods or standards for decommissioning operations, may also increase the funding requirements of, or accelerate the timing for funding of, the obligations related to the decommissioning of its Non-Utility NuclearEntergy Wholesale Commodities’ nuclear power plants. As a result, under any of these circumstances, Entergy'sEntergy’s results of operations, liquidity, and financial condition could be materially adversely affected.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
TheWholesale Commodities’ nuclear power plants owned by Entergy's Non-Utility Nuclear business will beare exposed to price risk to the extent they must compete for the advance sale of energy and capacity or accept spot prices in the day-ahead markets.risk.
Entergy and its subsidiaries are not guaranteed any rate of return on their capital investments in non-utility regulated businesses. In particular, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, owned by Entergy's Non-Utility Nuclear business, unless otherwise contracted, is subject to the fluctuation of market power prices. In order to reduce future price risk to desired levels, Entergy Wholesale Commodities utilizes contracts that are unit-contingent and Firm LD and various products such as forward sales, options, and collars. As of December 31, 2009, the2012, Entergy Wholesale Commodities nuclear power generation plants owned by Entergy's Non-Utility Nuclear business had sold forward 88%85%, 74%73%, 32%39%, 18%25% and 17%26% of its generation portfolio'sportfolio’s planned energy output for 2010, 2011, 2012, 2013, 2014, 2015, 2016, and 2014,2017, respectively. Many of Entergy’s Non-Utility Nuclear business’s existing long-term contracts expire by
Market conditions such as product cost, market liquidity, and other portfolio considerations influence the end of 2012.product and contractual mix. The obligations under most of theseunit-contingent agreements are contingentdepend on a generating asset that is operating; if the generation asset is not operating, the seller generally is not liable for damages. For some unit-contingent obligations, however, there is also a guarantee of availability that provides for the payment to the power purchaser of contract damages, if incurred, in the event the unit owner fails to deliver power as a result of the failure of the specified generation unit to generate power at or above a specified availability threshold. In addition, for those obligationsFirm LD sales transactions may be exposed to substantial operational price risk, a portion of which may be capped through the use of risk management products, to the extent that arethe plants do not unit-contingent, the unit owner will be required to pay the purchaser the difference between therun as expected and market price at the delivery point and theprices exceed contract price, and the amount of such payments could be substantial.prices.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Market prices may fluctuate substantially, sometimes over relatively short periods of time, and at other times experience sustained increases or decreases. Demand for electricity and its fuel stock can fluctuate dramatically, creating periods of substantial under- or over-supply. During periods of over-supply, prices might be depressed. Also, from time to time there may be political pressure, or pressure from regulatory authorities with jurisdiction over wholesale and retail energy commodity and transportation rates, to impose price limitations, credit requirements, bidding rules and other mechanisms to address volatility and other issues in these markets.
The price that different counterparties offer for various products including forward sales is influenced both by market conditions as well as the contract terms such as damage provisions, credit support requirements, and the number of available counterparties interested in contracting for the desired forward period. Depending on differences between market factors at the time of contracting versus current conditions, Non-Utility Nuclear'sEntergy Wholesale Commodities’ contract portfolio may have average contract prices above or or below current market prices, including at the expiration of the contracts, which couldmay significantly affect Non-Utility Nuclear'sEntergy Wholesale Commodities’ results of operations, financial condition, or liquidity. The recent economic downturn and liquidity.negative trends in the energy commodity markets have resulted in lower natural gas prices, and current prevailing market prices for electricity in the New York and New England power regions are therefore generally below the prices of Entergy Wholesale Commodities’ existing contracts in those regions. To the extent these market conditions persist, Entergy Wholesale Commodities’ realized price per MWh can be expected to continue to decline. See the “Results of Operations, Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. With operating licenses for Indian Point 2 and Indian Point 3 expiring in 2013 and 2015, respectively, and as a consequence of any delays in obtaining extension of the operating licenses and any other approvals required for continued operation of the plants, Entergy Wholesale Commodities may enter into fewer unit-contingent forward sales contracts for output from such plants for periods beyond the license expiration.
Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy'sEntergy’s control to a significant degree, are:
| · | prevailing market prices for natural gas, uranium (and its conversion, enrichment, and fabrication), coal, oil, and other fuels used in electric generation plants, including associated transportation costs, and supplies of such commodities; |
| · | availability of competitively priced alternative energy sources and the requirements of a renewable portfolio standard; |
| · | changes in production and storage levels of natural gas, lignite, coal and crude oil, and refined products; |
| · | liquidity in the general wholesale electricity market, including the number of creditworthy counterparties available and interested in entering into forward sales agreements for Entergy’s full hedging term; |
| · | the actions of external parties, such as the FERC and local independent system operators and other state or Federal energy regulatory bodies, that may impose price limitations and other mechanisms to address some of the volatility in the energy markets; |
| · | electricity transmission, competing generation or fuel transportation constraints, inoperability, or inefficiencies; |
| · | the general demand for electricity, which may be significantly affected by national and regional economic conditions; |
| · | weather conditions affecting demand for electricity or availability of hydroelectric power or fuel supplies; |
| · | the rate of growth in demand for electricity as a result of population changes, regional economic conditions, and the implementation of conservation programs; |
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| · | regulatory policies of state agencies that affect the willingness of Entergy's Non-Utility NuclearEntergy Wholesale Commodities customers to enter into long-term contracts generally, and contracts for energy in particular; |
| · | increases in supplies due to actions of current Entergy Non-Utility NuclearWholesale Commodities competitors or new market entrants, including the development of new generation facilities, expansion of existing generation facilities, the disaggregation of vertically integrated utilities, and improvements in transmission that allow additional supply to reach Entergy's Non-Utility NuclearEntergy Wholesale Commodities’ nuclear markets; |
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| · | union and labor relations; |
| · | changes in Federal and state energy and environmental laws and regulations and other initiatives, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI); |
| · | changes in law resulting from federal or state energy legislation or legislation subjecting energy derivatives used in hedging and risk management transactions to governmental regulation; and |
| · | natural disasters, terrorist actions, wars, embargoes, and other catastrophic events. |
Entergy's Non-Utility NuclearThe Entergy Wholesale Commodities business is subject to substantial governmental regulation and may be adversely affected by legislative, regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
Entergy's Non-Utility NuclearThe Entergy Wholesale Commodities business is subject to extensive federal, state, and local laws and regulation. Compliance with the requirements under these various regulatory regimes may cause the Non-Utility NuclearEntergy Wholesale Commodities business to incur significant additional costs, and failure to comply with such requirements could result in the shutdown of the non-complying facility, the imposition of liens, fines and/or civil or criminal liability.
Public utilities under the Federal Power Act are required to obtain FERC acceptance of their rate schedules for wholesale sales of electricity. Each of the Non-Utility Nuclear business'sowners of the Entergy Wholesale Commodities nuclear power plants, as well as Entergy Nuclear Power Marketing, LLC, is a "public utility"“public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy. The FERC has granted these generating and power marketing companies the authority to sell electricity at market-based rates. The FERC’s orders that grant the Non-Utility Nuclear business'sEntergy Wholesale Commodities’ generating and power marketing companies market-based rate authority reserve the right to revoke or revise that authority if the FERC subsequently determines that the Non-Utility NuclearEntergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Non-Utility Nuclear business'sEntergy Wholesale Commodities’ market-based sales are subject to certain market behavior rules, and if any of its generating and power marketing companies were deemed to have violated one of those rules, they would be subject to potential disgorgement of profits associated with the violation and/or suspension or revocation of their market-based rate authority and potential penalties of up to $1 million per day per violation. If the Non-Utility Nuclear business'sEntergy Wholesale Commodities’ generating or power marketing companies were to lose their market-based rate authority, such companies would be required to obtain the FERC’s acceptance of a cost-of-service rate schedule and could become subject to the accounting, record-keeping, and reporting requirements that are imposed on utilities with cost-based rate schedules. This could have an adverse effect on the rates the Non-Utility NuclearEntergy Wholesale Commodities business charges for power from its facilities.
The Non-Utility NuclearEntergy Wholesale Commodities business is also affected by legislative and regulatory changes, as well as changes to market design, market rules, tariffs, cost allocations, and bidding rules imposed by the existing Independent System Operators. The Independent System Operators that oversee most of the wholesale power markets impose, and in the future may continue to impose, mitigation, including price limitations, offer caps and other mechanisms, to address some of the volatility and the potential exercise of market power in these markets. These types of price limitations and other regulatory mechanisms may have an adverse effect on the profitability of the Non-Utility Nuclear business'sEntergy Wholesale Commodities business’ generation facilities that sell energy and capacity into the wholesale power markets. For further information regarding federal, state and local laws and regulation applicable to the Entergy Wholesale Commodities business, see the “Regulation of Entergy’s Business” section in Part I, Item 1.
The regulatory environment applicable to the electric power industry has undergone substantial changes over the past several years as a result of restructuring initiatives at both the state and federal levels. These changes are ongoing and Entergy cannot predict the future design of the wholesale power markets or the ultimate effect that the changing regulatory environment will have on the Non-Utility NuclearEntergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
material market design changes, including the elimination of a single clearing price mechanism and have raised claims that the competitive marketplace is not working because energy prices in wholesale markets exceed the marginal cost of operating nuclear power plants, as well as proposals to re-regulate the markets, impose a generation tax, or require divestitures by generating companies to reduce their market share.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Other proposals to re-regulate may be made and legislative or other attention to the electric power market restructuring process may delay or reverse the deregulation process, which could require material changes to business planning models. If competitive restructuring of the electric power markets is reversed, modified, discontinued, or delayed, the Non-Utility Nuclear business'sEntergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially adversely affected.
The power plants owned by the Entergy Wholesale Commodities business are subject to impairment charges in certain circumstances, which could have a material effect on Entergy’s results of operations, financial condition or liquidity.
Entergy reviews long-lived assets held in all of its business segments whenever events or changes in circumstances indicate that recoverability of these assets is uncertain. Generally, the determination of recoverability is based on the undiscounted net cash flows expected to result from such operations and assets. Projected net cash flows depend on the future operating costs associated with the assets, the efficiency and availability of the assets and generating units, and the future market and price for energy over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business are subject to impairment if adverse market conditions arise and continue (such as expected long-term declines in market prices for electricity), if adverse regulatory events occur (including with respect to environmental regulation), if a unit ceases operation or if a unit’s operating license is not renewed. Moreover, the failure of the Entergy Wholesale Commodities business to achieve forecasted operating results and cash flows, an unfavorable change in forecasted operating results or cash flows, or a decline in observable industry market multiples could all result in potential impairment charges for the affected assets.
As discussed in the “Entergy Wholesale Commodities - Property” section in Part I, Item 1, the operating licenses for Indian Point 2 and Indian Point 3 expire in 2013 and 2015, respectively, and are currently the subject of license renewal processes at the NRC and the state in which the plants operate, and the Vermont Yankee plant is the subject of certain state and federal proceedings and federal litigation relating to continued operation of that plant. As discussed in Note 1 to the financial statements, Entergy recognized an impairment charge for the Vermont Yankee plant in 2012. In addition, if Entergy concludes that any of these nuclear power plants is unlikely to operate significantly beyond its current license expiration date, which conclusion would be based on a variety of factors, such a conclusion could result in an impairment of part or all of the carrying value of the plant. Any impairment charge taken by Entergy with respect to its long-lived assets, including the power plants owned by the Entergy Wholesale Commodities business, would likely be material in the quarter that the charge is taken and could otherwise have a material effect on Entergy’s results of operations, financial condition, or liquidity.
General Business Risks
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Entergy and the Utility operating companies depend on access to the capital markets and, at times, may face potential liquidity constraints, which could make it more difficult to handle future contingencies such as natural disasters or substantial increases in gas and fuel prices. Disruptions in the capital and credit markets may adversely affect EntergyEntergy’s and its subsidiaries'subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy'sEntergy’s business is capital intensive and dependent upon its ability to access capital at reasonable rates and other terms. At times there are also spikes in the price for natural gas and other commodities that increase the liquidity requirements of the Utility operating companies.companies and Entergy Wholesale Commodities. In addition, Entergy'sEntergy’s and the Utility operating companies'companies’ liquidity needs could significantly increase in the event of a hurricane or other weather-related or unforeseen disaster similar to that experienced in Entergy'sEntergy’s service territory with Hurricane Katrina and Hurricane Rita in 2005, and Hurricane Gustav and Hurricane Ike in 2008.2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
purchased power costs or storm restoration costs, higher than expected pension contributions, an acceleration of payments or decreased credit lines, less cash flow from operations than expected, or other unknown events, such as future storms, could cause the financing needs of Entergy and its subsidiaries to increase. In addition, accessing the debt capital markets more frequently in these situations may result in an increase in leverage. Material leverage increases could negatively affect the credit ratings of Entergy and the Utility operating companies, which in turn could negatively affect access to the capital markets.
The global capital and credit markets experienced extreme volatility and disruption in the fourth quarter of 2008 and much of 2009. The inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries'subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy'sEntergy’s control, such as the volatility and disruption in global capital and credit markets in 2008 and 2009, may create uncertainty that could increase its cost of capital or impair its ability to access the capital markets, including the ability to draw on its bank credit facilities. Entergy and its subsidiaries are unable to predict the degree of success they will have in renewing or replacing their credit facilities as they come up for renewal. Moreover, the size, terms, and covenants of any new credit facilities may not be comparable to, and may be more restrictive than, existing facilities. If Entergy and its subsidiaries are unable to access the credit and capital markets on terms that are reasonable, they may have to delay raising capital, issue shorter-term securities and/or bear an unfavorable cost of capital, which, in turn, could impact their ability to grow their businesses, decrease earnings, significantly reduce financial flexibility and/or limit Entergy'sEntergy Corporation’s ability to sustain its current common stock dividend level.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
A downgrade in Entergy Corporation'’s or its subsidiaries'’ credit ratings could negatively affect Entergy Corporation'’s and its subsidiaries'’ ability to access capital and/or could require Entergy Corporation or its subsidiaries to post collateral, accelerate certain payments, or repay certain indebtedness.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
There are a number of factors that rating agencies evaluate to arrive at credit ratings for each of Entergy Corporation and the Registrant Subsidiaries, including theeach Registrant’s regulatory framework, ability to cover liquidity requirements, the availability of committed external credit support,recover costs and Entergy Corporation's share repurchase program, dividend policyearn returns, diversification and other commitments for capital.financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation's,Corporation’s, any of the Utility operating companies'companies’, or System Entergy'sEnergy’s ratings, particularly below investment grade, borrowing costs would increase, the potential pool of investors and funding sources would likely decrease, and cash or letter of credit quality collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy Corporation'sCorporation’s and its subsidiaries'subsidiaries’ large customers, suppliers, and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation'sCorporation’s or its subsidiaries'subsidiaries’ ratings decline, particularly below investment grade, or if certain counterparties believe Entergy Corporation or the Utility operating companies are losing creditworthiness and demand adequate assurance under fuel, gas, and purchased power contracts, the counterparties may require posting of collateral in cash or letters of credit, prepayment for fuel, gas or purchased power or accelerated payment, or counterparties may decline business with Entergy Corporation or its subsidiaries. At December 31, 2009,2012, based on power prices at that time, Entergy had $369liquidity exposure for Entergy Wholesale Commodities business transactions of $203 million of collateral in place to support Entergy Nuclear Power Marketing transactional activity, consisting primarily of Entergy Corporationunder guarantees, but also including $20 million of guarantees that support letters of credit, and $2$7 million of posted cash collateral.collateral to the ISOs. As of December 31, 2009,2012, the creditliquidity exposure associated with Non-Utility NuclearEntergy Wholesale Commodities assurance requirements could increase by an estimated amount of up to $308$106 million for eacha $1 per MMBtu increase in gas prices in both the short- and long-term markets, but because market prices have fallen below most contract prices, the credit exposure would increase by only $8 million.markets. In the event of a decrease in Entergy Corporation'sCorporation’s credit rating to below investment grade, based on power prices as of December 31, 2009,2012, Entergy would have been required to provide approximately $73$48 million of additional cash or letters of credit under some of the agreements. The amount
Part I Item 1A & 1B
Entergy Corporation, guarantees Entergy would be required to replace will fluctuate depending on changes in power prices.Utility operating companies, and System Energy
The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial conditions,condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially adversely affected.
Entergy'sEntergy’s and the Utility operating companies'companies’ ability to complete construction of power generation facilities in a timely manner and within budget is contingent upon many variables and subject to substantial risks. These variables include, but are not limited to, project management expertise and escalating costs for materials, labor, and environmental compliance. Delays in obtaining permits, shortages in materials and qualified labor, suppliers and contractors not performing as required under their contracts, changes in the scope and timing of projects, poor quality initial cost estimates from contractors, the inability to raise capital on favorable terms, changes in commodity prices affecting revenue, fuel costs, or materials costs, downward changes in the economy, changes in law or regulation, including environmental compliance requirements, and other events beyond the control of the Utility operating companies or the Entergy Wholesale Commodities business may occur that may materially affect the schedule, cost, and performance of these projects. If these projects are significantly delayed or become subject to cost overruns or cancellation, Entergy and the Utility operating companies could incur additional costs and termination payments, or face increased risk of potential write-off of the investment in the project. For further information regarding capital expenditure plans and other uses of capital in connection with the potential construction of additional generation supply sources within the Utility operating companies'companies’ service territory, and as to the Entergy Wholesale Commodities business, see the "“Capital Expenditure Plans and Other Uses of Capital"” section of Management'sManagement’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
The Utility operating companies, System Energy, and Entergy's Non-Utility Nuclearthe Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to reliability standards, environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business operate are subject to extensive environmental regulation by local, state, and Federal authorities. These laws and regulations affect the manner in which the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business conduct their operations and make capital expenditures. These laws and regulations also affect how the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business manage air emissions, discharges to water, solid and hazardous waste storage and disposal, cooling and service water intake, the protection of threatened and endangered
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
species, hazardous materials transportation, and similar matters. Federal, state, and local authorities continually revise these laws and regulations, and the laws and regulations are subject to judicial interpretation and to the permitting and enforcement discretion vested in the implementing agencies. Developing and implementing plans for facility compliance with these requirements can lead to capital, personnel, and operation and maintenance expenditures. Violations of these requirements can subject the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties'parties’ claims for alleged health or property damages or for violations of applicable permits or standards. In addition, the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business are subject to liability under these laws for the costs of remediation of environmental contamination of property now or formerly owned or operated by the Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business and of property contaminated by hazardous substances they generate. The Utility operating companies are currently involved in proceedings relating to sites where hazardous substances have been released and may be subject to additional proceedings in the future. The Utility operating companies, System Energy, and the Non-Utility NuclearEntergy Wholesale Commodities business have incurred and expect to incur significant costs related to environmental compliance.
Emissions of nitrogen and sulfur oxides, mercury, particulates, greenhouse gases, and other regulated air contaminantsemissions from fossil-fueled generating plants are potentially subject to increased regulation, controls and mitigation expenses. In addition, existing air regulations and programs promulgated by the EPA often are challenged legally, sometimes resulting in large-scale changes to anticipated regulatory regimes.regimes and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, and initiatives to compel CO2greenhouse gas emission reductions, and water availability issues are discussed below.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy's business is also subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation and the SERC Reliability Corporation, are approved by the FERC and currently are being reviewed and amended. Significant capital expenditures for the Utility operating companies' transmission system could be required to achieve on-going compliance with the requirements under these regimes, and failure to comply with such requirements could result in the imposition of fines or civil penalties, and exposure to third party claims for alleged violations of applicable standards. The laws and regulations are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. The changes to the reliability requirements applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the changing reliability requirements will have on its business.
Entergy and its subsidiaries may not be able to obtain or maintain all required environmental regulatory approvals. If there is a delay in obtaining any required environmental regulatory approvals, or if Entergy and its subsidiaries fail to obtain, maintain, or comply with any such approval, the operation of its facilities could be stopped or become subject to additional costs. For further information regarding environmental regulation and environmental matters, see the "“Regulation of Entergy'’s Business – Environmental Regulation"” section of Part I, Item 1.
The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs related to reliability standards.
Entergy’s business is subject to extensive and mandatory reliability standards. Such standards, which are established by the North American Electric Reliability Corporation (NERC), the SERC Reliability Corporation (SERC), and other regional enforcement entities, are approved by the FERC and frequently are reviewed, amended, and supplemented. Failure to comply with such standards could result in the imposition of fines or civil penalties, and potential exposure to third party claims for alleged violations of such standards. The standards, as well as the laws and regulations that govern them, are subject to judicial interpretation and to the enforcement discretion vested in the implementing agencies. In addition to exposure to civil penalties and fines, the Utility operating companies have incurred and expect to incur significant costs related to compliance with new and existing reliability standards, including costs associated with the Utility operating companies’ transmission system and generation assets. The changes to the reliability standards applicable to the electric power industry are ongoing, and Entergy cannot predict the ultimate effect that the reliability standards will have on its Utility and Entergy Wholesale Commodities business.
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
The effects of weather and economic conditions, and the related impact on electricity and gas usage, may materially adversely affect the Utility operating companies'’ results of operations.
Temperatures above normal levels in the summer tend to increase summer cooling electricity demand and revenues, and temperatures below moderate levels in the winter tend to increase winter heating electricity and gas demand and revenues. As a corollary, moderate temperatures tend to decrease usage of energy and resulting revenues. Seasonal pricing differentials, coupled with higher consumption levels, typically cause the Utility operating companies to report higher revenues in the third quarter of the fiscal year than in the other quarters. Extreme weather conditions or storms, however, may stress the Utility operating companies'companies’ generation facilities and transmission and distribution systems, resulting in increased maintenance and capital costs (and potential increased financing needs), limits on their ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. These extreme conditions could have a material adverse effect on the Utility operating companies'companies’ financial condition, results of operations, and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Industrial sales volume was depressed in the latter part of 2008 and through most of 2009, in part because the overall economy declined, with lower usage across the industrial sector affecting both the large customer industrial segment as well as small and mid-sized industrial customers. DespiteIn addition, a number of Entergy’s larger industrial customers have the apparently improving economic conditions in the service territoriesability to develop cogeneration facilities that would enable them to greatly eliminate or reduce their purchases of the Utility operating companies in the fourth quarter of 2009, itelectricity from Entergy. It is possible that continued or recurrent poor economic conditions combined with increasing rates in certainor the departure of the Utility operating companies' service territories,one or more large customers to cogeneration could result in slower or declining sales growth and increased bad debt expense, relative to recent years, which could materially adversely affect Entergy'sEntergy’s and the Utility operating companies'companies’ results of operations, financial condition, and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The effects of climate change and environmental and regulatory obligations intended to compel CO2greenhouse gas emission reductions or to place a price on greenhouse gas emissions could materially adversely affect the financial condition, results of operations, and liquidity of Entergy and the Utility operating companies.
In an effort to address climate change concerns, Federal, state, and local authorities are calling for additional laws and regulations aimed at known or suspected causes of climate change. For example, in response to the United States Supreme Court'sCourt’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other "greenhouse gases"“greenhouse gases” under the Clean Air Act, the EPA, various environmental interest groups, and other organizations are focusing considerable attention on CO2 emissions from power generation facilities and their potential role in climate change. In 2010, EPA promulgated its first regulations controlling greenhouse gas emissions from certain vehicles and from new and significantly modified stationary sources of emissions, including electric generating units. In 2012, EPA proposed a CO2 emission standard for new sources; this standard is expected to be finalized in 2013. Additionally, EPA is expected to develop a proposed CO2 emission standard for existing power generation facilities perhaps as early as 2013. As examples of state action, in the Northeast, the Regional Greenhouse Gas Initiative (RGGI) establishes a cap on CO2 emissions from electric power plants and requires generators to purchase emission permits to cover their CO2 emissions, and a similar program has been developed in California. Developing and implementing plans for compliance with CO2greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance expenditures.expenditures and could significantly affect the economic position of existing facilities and proposed projects; moreover, long-term planning to meet environmental requirements can be negatively impacted and costs may increase to the extent laws and regulations change prior to full implementation. Violations of such requirements may subject Entergy Wholesale Commodities and the Utility operating companies to enforcement actions, capital expenditures to bring existing facilities into compliance, additional operating costs or operating restrictions to achieve compliance, remediation and clean-up costs, civil penalties, and exposure to third parties'parties’ claims for alleged health or property damages or for violations of applicable permits or standards. To the extent Entergy believes any of these costs are recoverable in rates, however, additional material rate increases for customers could be resisted by Entergy'sEntergy’s regulators and, in extreme cases, Entergy'sEntergy’s regulators might deny or defer timely recovery of these costs. Future changes in environmental regulation governing the emission of CO2 and other "greenhouse gases"greenhouse gases could make some of Entergy'sEntergy’s electric generating units uneconomical to maintain or operate, and could increase the difficulty that Entergy and its subsidiaries have with obtaining or maintaining required environmental regulatory approvals, which could also materially adversely affect the financial condition, results of operations and liquidity of Entergy and the Utility operating companies.its subsidiaries. In addition, severalmultiple lawsuits currently are pending or are reasonably expected against emitters of greenhouse gases alleging that these companies are liable for personal injuries and property damage caused by climate change. These lawsuits seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, physical risks from climate change include an increase in sea level, wind and storm surge damages, wetland and barrier island erosion, risks of flooding and changes in weather conditions, such as changes in precipitation, average temperatures, and potential increased impacts of extreme weather conditions or storms. Entergy ownssubsidiaries own assets in, and serves,serve, communities that are at risk from sea level rise, changes in weather conditions, storms, and loss of the protection offered by coastal wetlands. A significant portion of the nation’s oil and gas infrastructure is located in these areas and susceptible to storm damage that could be aggravated by wetland and barrier island erosion, which could give rise to fuel supply interruptions and price spikes. Entergy and its subsidiaries also face the risk that climate change could impact the availability and quality of water supply necessary for operations.
These and other physical changes could result in changes in customer demand, increased costs associated with repairing and maintaining generation facilities and transmission and distribution systems resulting in increased maintenance and capital costs (and potential increased financing needs), limits on the Entergy System'sSystem’s ability to meet peak customer demand, increased regulatory oversight, and lower customer satisfaction. Also, to the extent that climate change adversely impacts the economic health of a region or results in energy conservation or demand side management programs, it may adversely impact customer demand and revenues. Such physical or operational risks could have a material adverse effect on Entergy'sEntergy’s, Entergy Wholesale Commodities’, and the Utility operating companies'companies’ financial condition, results of operations, and liquidity.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially adversely affect Entergy's and its subsidiaries' results of operations, financial condition and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Continued and future availability and quality of water for cooling, process, and sanitary uses could materially affect the financial condition, results of operations, and liquidity of the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ business.
Water is a vital natural resource that also is critical to the Utility operating companies, System Energy, and Entergy Wholesale Commodities’ business operations. Entergy’s facilities use water for cooling, boiler make-up, sanitary uses, potable supply, and many other uses. Two of Entergy’s Utility operating companies own and/or operate hydroelectric facilities. Accordingly, water availability and quality are critical to Entergy’s business operations. Impacts to water availability or quality could negatively impact both operations and revenues.
Entergy secures water through various mechanisms (ground water wells, surface waters intakes, municipal supply, etc.) and operates under the provisions and conditions set forth by the provider and/or regulatory authorities. Entergy also obtains and operates in substantial compliance with water discharge permits issued under various provisions of the Clean Water Act. Regulations and authorizations for both water intake and use and for waste discharge can become more stringent in times of water shortages, low flows in rivers, low lake levels, low groundwater aquifer volumes, and similar conditions. The increased use of water by industry, agriculture, and the population at large, population growth, and the potential impacts of climate change on water resources may cause water use restrictions that affect Entergy and its subsidiaries.
Entergy and its subsidiaries may not be adequately hedged against changes in commodity prices, which could materially affect Entergy’s and its subsidiaries’ results of operations, financial condition, and liquidity.
To manage their near-term financial exposure related to commodity price fluctuations, Entergy and its subsidiaries, including the Utility operating companies and the Entergy Wholesale Commodities business, may enter into contracts to hedge portions of their purchase and sale commitments, weather positions, fuel requirements, and inventories of natural gas, uranium (and its conversion), lignite, coal, refined products, and other commodities, within established risk management guidelines. As part of this strategy, Entergy and its subsidiaries may utilize fixed- and variable-price forward physical purchase and sales contracts, futures, financial swaps, and option contracts traded in the over-the-counter markets or on exchanges. However, Entergy and its subsidiaries normally cover only a portion of the exposure of their assets and positions to market price volatility, and the coverage will vary over time. In addition, Entergy also elects to leave certain volumes during certain years unhedged. To the extent Entergy and its subsidiaries have unhedged positions, fluctuating commodity prices can materially adversely affect Entergy'sEntergy’s and its subsidiaries'subsidiaries’ results of operations and financial position.
Although Entergy and its subsidiaries devote a considerable effort to these risk management strategies, they cannot eliminate all the risks associated with these activities. As a result of these and other factors, Entergy and its subsidiaries cannot predict with precision the impact that risk management decisions may have on their business, results of operations, or financial position.
Entergy has guaranteed or indemnified the performance of a portion of the obligations relating to hedging and risk management activities. Reductions in Entergy'sEntergy’s or its subsidiaries'subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or Letterletter of Credit qualitycredit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy'sEntergy’s or its subsidiaries'subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy's Non-Utility Nuclear Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially adversely affect the Utility operating companies'companies and Non-Utility Nuclear's business.Entergy Wholesale Commodities.
Entergy's Utility operating companies' and its Non-Utility Nuclear subsidiaries'The hedging and risk management activitiespractices of the Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties that owe Entergy and its subsidiaries money, energy, or other commodities will not perform their obligations. Currently, some hedging agreements contain provisions that require the counterparties to provide credit support to secure all or part of their obligations to Entergy or its subsidiaries. If the counterparties to these arrangements fail to
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
perform, Entergy or its subsidiaries might be forced to act onmay enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements or draw on the credit support provided by the counterparties, which credit support may not always be adequate to cover the related obligations. In such event, Entergy and its subsidiaries might incur losses in addition to amounts, if any, already paid to the counterparties. In addition, the credit commitments of Entergy'sEntergy’s lenders under its bank facilities may not be honored for a variety of reasons, including unexpected periods of financial distress affecting such lenders, which could materially adversely affect the adequacy of its liquidity sources.
New legislationThe Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may subjectadversely affect the ability of the Utility operating companies and Entergy’s Non-Utility Nuclearthe Entergy Wholesale Commodities business to utilize certain commodity derivatives for hedging and mitigating commercial risk.
The Wall Street Transparency and Accountability Act of 2010, which was enacted on July 21, 2010 as part of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and the rules and regulations promulgated under the act impose governmental regulation of energy derivatives used in hedging and risk management transactions, which may materially adversely affect the Utility operating companies’ and Entergy’s Non-Utility Nuclear business.
New legislation may subject the Utility operating companies and Entergy’s Non-Utility Nuclear business to governmental regulation relating to certain hedging transactions. For example, Congress is considering legislation to impose restrictions on the use of over-the-counter derivatives,derivative market, including energy derivatives. The United States House of Representatives passed its version of the legislation (H.R. 4173, Title III) on December 11, 2009. If such legislation becomes law, Entergy’s subsidiaries could potentially face higher costs to hedge their risks, fewer potential counterparties still active in the newly regulated marketplace, and increased liquidity requirements. Under the proposed legislation, hedging and other risk management transactions conductedcommodity swaps used by the Utility operating companies and Entergy’s Non-Utility Nuclearthe Entergy Wholesale Commodities business would be regulatedto hedge and mitigate commercial risk. Under the act, certain swaps are subject to mandatory clearing and exchange trading requirements. Swap dealers and major market participants in the swap market are subject to capital, margin, registration, reporting, recordkeeping, and business conduct requirements with respect to their swap activities. Position limits may also apply to certain swaps activities. Non-swap dealers and non-major market participants, which Entergy expects to qualify as, are subject to reporting, recordkeeping, and business conduct requirements (i.e. anti-manipulation, anti-disruptive trading practices, and whistleblower provisions) with respect to their swap activities. Position limit rules promulgated by the Commodity Futures Trading Commission.Commission were vacated by the US District Court for the District of Columbia. In response, the Commodity Futures Trading Commission has announced it will appeal the court’s decision. If the Commodity Futures Trading Commission’s appeal is successful, position limits may apply to certain of Entergy’s swaps activities. The act required the applicable regulators, which in the case of commodity swaps will be the Commodity Futures Trading Commission, to engage in substantial rulemaking in order to implement the provisions of the act and such legislation were to become law withoutrulemaking has been largely completed. Both the addition of appropriate exemptions for energy transactions and energy markets, then Entergy believes that the forward hedging strategies and other risk management activities of its subsidiaries could either be curtailed or become significantly more expensive. A substantial number of these hedge transactions currently used by Entergy’s subsidiaries rely upon bilaterally negotiated contracts that are unsecured or utilize corporate guarantees or fixed credit support
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies and System Energy
structures. If Entergy’s subsidiaries werethe Entergy Wholesale Commodities business currently utilize commodity swaps to hedge and mitigate commodity price risk. It is not known whether the act and regulations promulgated under the act will have an adverse effect upon the market for the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business. However, to the extent that the act and regulations promulgated under the act have the effect of increasing the price of such commodity swaps or limiting or reducing the availability of such commodity swaps, whether through the imposition of additional capital, margin, or compliance costs upon market participants, the imposition of position limits, or otherwise, the financial performance of the Utility operating companies and/or the Entergy Wholesale Commodities business may be adversely affected. To the extent that the Utility operating companies and the Entergy Wholesale Commodities business may be required to “clear” their transactions, or to post margin based on the mark-to-market forward price of power (asin connection with existing or future commodity swaps in addition to any margin is calculatedcurrently posted by Commodity Futures Trading Commission-regulated exchanges and clearing entities), then these subsidiaries wouldsuch entities, such entities may need to arrange a substantial amountsecure additional sources of additionalcapital to meet such liquidity in order to maintain their current level of hedging and risk management activities.needs or cease utilizing such commodity swaps.
Market performance and other changes may decrease the value of benefit plan assets, which then could require significant additional funding.
The performance of the capital markets affects the values of the assets held in trust under Entergy'sEntergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy'sEntergy’s benefit plan liabilities. The recent significant volatilityVolatility in the capital markets has affected the market value of these assets, which may affect Entergy'sEntergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy'sEntergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding. The funding requirements of the obligations related to the pension benefit plans can also increase as a result of changes in, among other factors, retirement rates, life expectancy assumptions, or Federal regulations. Guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act of 2006 as a result of these discussions and efforts may affect the level of Entergy's pension contributions in the future. For further information regarding Entergy'sEntergy’s pension and other postretirement benefit plans, reference is maderefer to the "“Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits"” section of Management'sManagement’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the consolidated financial statements.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The litigation environment in the states in which certain Entergy subsidiaries operate poses a significant risk to those businesses.
Entergy and its subsidiaries are involved in the ordinary course of business in a number of lawsuits involving employment, commercial, asbestos, hazardous material and ratepayer matters, and injuries and damages issues, among other matters. StatesThe states in which the Utility operating companies operate, in particular Louisiana, Mississippi, and Texas, have proven to be unusually litigious environments. Judges and juries in these states have demonstrated a willingness to grant large verdicts, including punitive damages, to plaintiffs in personal injury, property damage, and business tort cases. Entergy and its subsidiaries use legal and appropriate means to contest litigation threatened or filed against them, but the litigation environment in these states poses a significant business risk.
Terrorist attacks, future warincluding cyber attacks, and failures or riskbreaches of warEntergy’s and its subsidiaries’ technology systems may adversely affect Entergy'sEntergy’s results of operations.
As power generators and distributors, Entergy and its subsidiaries face heightened risk of an act or threat of terrorism, including physical and cyber attacks, either as a direct act against one of Entergy'sEntergy’s generation facilities, or an act against the transmission and distribution infrastructure used to transport power whichthat affects its ability to operate.operate, or an act against the information technology systems and network infrastructure of Entergy and its subsidiaries.
Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure. Despite the implementation of security measures by Entergy and its subsidiaries, all technology systems are vulnerable to disability, failures, or unauthorized access due to such activities. If Entergy’s or its subsidiaries’ technology systems were to fail or be breached and be unable to recover in a timely way, Entergy or its subsidiaries may be unable to fulfill critical business functions, and sensitive confidential and other data could be compromised.
If any such an attackattacks, failures or breaches were to occur, Entergy'sEntergy’s and the Utility operating companies’ business, financial condition, and results of operations could be materially adversely affected. The risk of terroristsuch attacks, failures, or breaches also may cause Entergy and the Utility operating companies to incur increased capital and operating costs to implement increased security for its nuclear power plants and other facilities, such as additional physical facility security and additional security personnel.personnel, and for systems to protect its information technology and network infrastructure systems.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy's,Entergy’s, the Utility operating companies'companies’, and System Energy'sEnergy’s results of operations, financial condition and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various financial transactions and results of operations to estimate their obligations to taxing authorities. These tax obligations include income, franchise, real estate, sales and use, and employment-related taxes. These judgments include reserves for potential adverse outcomes regarding tax positions that have been taken. Entergy and its subsidiaries also estimate their ability to utilize tax benefits, including those in the form of carryforwards for which the
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
benefits have already been reflected in the financial statements. Changes in Federal,federal, state, or local tax laws, adverse tax audit results or adverse tax rulings on positions taken by Entergy and its subsidiaries could negatively affect Entergy's,Entergy’s, the Utility operating companies'companies’, and System Energy'sEnergy’s results of operations, financial condition, and liquidity. For further information regarding Entergy'sEntergy’s accounting for tax obligations, reference is maderefer to Note 3 to the financial statements.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Entergy and the Utility operating companies may be unable to satisfy the conditions or obtain the approvals to complete the transaction with ITC or such approvals may contain material restrictions or conditions.
See “Plan to Spin Off the Utility’s Transmission Business” in Entergy Corporation’s Management’s Financial Discussion and Analysis for a discussion of the agreements that Entergy entered in December 2011 to spin off its transmission business and merge it with a newly-formed subsidiary of ITC Holdings Corp. The consummation of the ITC transaction is subject to numerous conditions, including (i) consummation of certain transactions and financings contemplated by the Merger Agreement and the Separation Agreement (such as the separation of the Transmission Business conducted by the Utility operating companies, (ii) obtaining the required ITC shareholder approvals, and (iii) the receipt of certain regulatory approvals from governmental agencies necessary to consummate the ITC transaction, and that no such regulatory approvals impose a burdensome condition on ITC or Entergy as described in the Merger Agreement. Entergy can make no assurances that the ITC transaction will be consummated on the terms or timeline currently contemplated, or at all. Governmental agencies may not approve the ITC transaction or may impose conditions to the approval of the ITC transaction or require changes to the terms of the ITC transaction. Any such conditions or changes could have the effect of delaying completion of the ITC transaction, imposing costs on or limiting the revenues of Entergy or the Utility operating companies, or otherwise reducing the anticipated benefits of the ITC transaction. Any condition or change could result in a burdensome condition on the Transmission Business, the Utility operating companies, or ITC under the Merger Agreement and might cause Entergy or ITC to abandon the ITC transaction. In addition, Entergy must pay its costs related to the ITC transaction including, legal, accounting, advisory, financing and filing fees, and printing costs, whether the ITC transaction is completed or not. Any failure to consummate the ITC transaction as currently contemplated, or at all, could have a material effect on the business and results of operations of Entergy and the Utility operating companies and the trading price of Entergy Corporation’s common stock could be adversely affected.
(Entergy Gulf States Louisiana and Entergy New Orleans)
The effect of higher purchased gas cost charges to customers may adversely affect Entergy Gulf States Louisiana'sLouisiana’s and Entergy New Orleans'Orleans’s results of operations and liquidity.
Gas rates charged to retail gas customers are comprised primarily of purchased gas cost charges, which provide no return or profit to Entergy Gulf States Louisiana or Entergy New Orleans, and distribution charges, which provide a return or profit to the utility. Distribution charges are affected by the amount of gas sold to customers. Purchased gas cost charges, which comprise most of a customer'scustomer’s bill and may be adjusted quarterly,monthly, represent gas commodity costs that Entergy Gulf States Louisiana or Entergy New Orleans recovers from its customers. Entergy Gulf States Louisiana'sLouisiana’s or Entergy New Orleans'Orleans’s cash flows can be affected by differences between the time period when gas is purchased and the time when ultimate recovery from customers occurs. When purchased gas cost charges increase substantially reflecting higher gas procurement costs incurred by Entergy Gulf States Louisiana or Entergy New Orleans, customer usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy Gulf States Louisiana or Entergy New Orleans.Orleans which could adversely affect results of operations.
(System Energy)
System Energy owns and operates a single nuclear generating facility, and it is dependent on affiliated companies for all of its revenues.
System Energy'sEnergy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% ownership/leasehold interest in Grand Gulf. Charges under the Unit Power Sales Agreement are paid by the Utility operating companies as consideration for their respective entitlements to receive capacity and energy and are payable on a full cost-of-service basis only so long as Grand Gulf remains in commercial operation.energy. The useful economic life of Grand Gulf is finite and is limited by the terms of its operating license, which is currently due to expire on November 1, 2024. System Energy'sEnergy filed in October 2011 an application with the NRC for an extension of Grand Gulf’s operating license to 2045. System Energy’s financial condition depends both on the receipt of payments from the Utility operating companies under the Unit Power Sales Agreement and on the continued commercial operation of Grand Gulf.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies'companies’ support of System Energy (including the Capital Funds Agreement), see the "Grand Gulf - Related Agreements"“Grand Gulf-Related Agreements” section of Note 8 to the financial statements and the "Utility“Sale and Leaseback Transactions” section of Note 10 to the financial statements, and the “Utility - System Energy and Related Agreements"Agreements” section of Part I, Item 1.
(Entergy Corporation)
Entergy Corporation'’s holding company structure could limit its ability to pay dividends.
Entergy Corporation is a holding company with no material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation'sCorporation’s ability to pay dividends on its common stock depends on the payment to it of dividends or distributions by its subsidiaries. The payments of dividends or distributions to Entergy Corporation by its subsidiaries in turn depend on their results of operations and cash flows and other items affecting retained earnings.earnings, and on any applicable legal, regulatory, or contractual limitations on subsidiaries’ ability to pay such dividends or distributions. Provisions in the organizational documents, indentures for debt issuances, and other agreements of certain of Entergy Corporation'sCorporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, reference is made tosee the "COMMON EQUITY – “Retained Earnings and Dividend Restrictions"” section of Note 7 to the financial statements.
If completed, the transaction with ITC may not achieve its anticipated results.
Entergy Corporation's proposed spin-off of its Non-Utility Nuclear business is subject to risks inherent to a large-scaleentered into the ITC transaction subject to regulatory approvals andwith the completion of complex financings.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The proposed spin-off of Entergy Corporation's Non-Utility Nuclear business is subject to multiple risks and uncertainties,expectation that it would result in various benefits, including the risk that the spin-off will not be consummated, the risk that the financing transactions contemplatedreceipt by Entergy’s shareholders of shares of ITC common stock as parta result of the spin-off cannot be consummated on terms and conditions acceptable to Entergy Corporation or the risk that state and Federal regulatory jurisdictions may impose conditions to the transaction not acceptable to Entergy Corporation.transaction. If the spin-offITC transaction is consummated, it is possible that Entergy Corporation or Enexus Energy Corporation, the wholly-owned subsidiary of Entergy whose shares will be distributed in the spin-off , may not achieve the full strategic, financial, operational, and financialregulatory benefits to Entergy and its shareholders that they expect willEntergy expected would result from the ITC transaction may not be achieved or that such benefits may be delayed or not occur due to unforeseen changes in market, and economic or regulatory conditions or other events. As a result, the aggregate market price of the common stock of Entergy Corporation and Enexus Energythe shares of ITC common stock that shareholders of Entergy Corporation as separate companieswould receive in the ITC transaction could be less than the market price of Entergy Corporation'sCorporation’s common stock if the spin-offITC transaction had not occurred.
ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
Plan to Spin Off the Utility’s Transmission Business
See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt and preferred securities.
Results of Operations
Net Income
20092012 Compared to 2008
Net income increased $19.7 million primarily due to lower other operation and maintenance expenses and a lower effective income tax rate, partially offset by lower net revenue, higher depreciation and amortization expenses, higher nuclear refueling outage expenses, and higher interest expense.
2008 Compared to 20072011
Net income decreased $92.0$12.5 million primarily due to higher other operation and maintenance expenses and higher depreciation and amortization expenses, andtaxes other than income taxes, partially offset by a lower effective income tax rate.
2011 Compared to 2010
Net income decreased $7.7 million primarily due to a higher effective income tax rate, partially offset by higher net revenue. Thelower other income, and higher other operation and maintenance expenses, resulted primarily from the write-off of approximately $70.8 million of costs as a result of the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas' 2006 base rate case. The 2006 base rate case is discussed in more detail in Note 2 to the financial statements.partially offset by higher net revenue, lower depreciation and amortization expenses, and lower interest expense.
Net Revenue
20092012 Compared to 20082011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2012 to 2011.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 1,252.3 | |
| Retail electric price | | | 23.4 | |
| Net wholesale revenue | | | 5.7 | |
| Transmission revenue | | | (9.6 | ) |
| Volume/weather | | | (19.0 | ) |
| Other | | | 0.2 | |
| 2012 net revenue | | $ | 1,253.0 | |
The retail electric price variance is primarily due to an increase in the energy efficiency rider, as approved by the APSC, effective July 2012. The energy efficiency rider revenues are offset by costs included in other operation and maintenance expenses and have no effect on net income.
The net wholesale revenue variance is primarily due to higher wholesale billings to affiliate companies due to higher expenses and lower wholesale energy costs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The transmission revenue variance is primarily due to a revision to transmission investment equalization billings under the System Agreement among the Utility operating companies (for the approximate period of 1996 – 2011) recorded in the fourth quarter 2011.
The volume/weather variance is primarily due to the effects of milder weather, as compared to the prior period, primarily on residential sales.
Gross operating revenues, fuel and purchased power expenses, and other regulatory credits
Gross operating revenues increased primarily due to an increase of $39.2 million in rider revenues related to higher System Agreement production cost equalization payments and an increase of $16.1 million in rider revenues due to an increase in the energy efficiency rider effective July 2012. The increase was partially offset by the June 2012 refund to AmerenUE of $30.6 million, including interest, of rough production cost equalization payments collected from AmerenUE. Entergy Arkansas had previously recorded a regulatory provision for the potential refund to AmerenUE. The result of the refund is a decrease in gross revenues with an offsetting increase in other regulatory credits. See “2007 Rate Filing Based on Calendar Year 2006 Production Costs” in Note 2 to the financial statements for a discussion of the FERC order in the System Agreement production cost equalization proceedings.
Fuel and purchased power expenses increased primarily due to an increase in the recovery from customers of deferred fuel costs, partially offset by a decrease in the average market price of purchased power.
Other regulatory credits increased primarily due to the June 2012 refund to AmerenUE, as discussed above.
2011 Compared to 2010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 20092011 to 2008.2010.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $1,117.9
|
Provision for regulatory proceedings | | (26.1) |
Volume/weather | | (24.4) |
Retail electric price | | 26.5 |
Other | | 8.5 |
2009 net revenue | | $1,102.4
|
The provision for regulatory proceedings variance is primarily due to provisions recorded in 2009. See Note 2 to the financial statements for a discussion of regulatory proceedings affecting Entergy Arkansas.
The volume/weather variance is primarily due to the effect of less favorable weather and an 11.6% volume decrease in industrial sales primarily in the mid to small customer class.| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 1,216.7 | |
| Retail electric price | | | 31.0 | |
| ANO decommissioning trust | | | 26.4 | |
| Transmission revenue | | | 13.1 | |
| Capacity acquisition recovery | | | (10.3 | ) |
| Net wholesale revenue | | | (11.9 | ) |
| Volume/weather | | | (15.9 | ) |
| Other | | | 3.2 | |
| 2011 net revenue | | $ | 1,252.3 | |
The retail electric price variance is primarily due to the recovery of 2008 extraordinary storm costs as approved by the APSC,a base rate increase effective January 2009, which is discussed inJuly 2010. See Note 2 to the financial statements. Also contributing tostatements for more discussion of the increase are increases in the capacity acquisition riderrate case settlement.
The ANO decommissioning trust variance is primarily related to the Ouachita acquisition.deferral of investment gains from the ANO 1 and 2 decommissioning trust in 2010 in accordance with regulatory treatment. The gains resulted in an increase in 2010 in interest and investment income and a corresponding increase in regulatory charges with no effect on net income effect of the Ouachita cost recoveryincome.
The transmission revenue variance is limitedprimarily due to a portion representing an allowed return on equity withrevision to transmission investment equalization billings under the remainder offset by Ouachita plant costsSystem Agreement among the Utility operating companies (for the approximate period of 1996 – 2011) recorded in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes.the fourth quarter 2011.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues decreased primarily due to:
· | a decrease of $119.9 million in gross wholesale revenue due to a decrease in the average price of energy available for resale sales; |
· | a decrease of $63.2 million in fuel cost recovery revenues due to a change in the energy cost recovery rider effective April 2009 and decreased usage; and |
· | a decrease of $24.4 million related to volume/weather, as discussed above. |
The decrease was offset by an increase of $90.7 million in rider revenues.
Fuel and purchased power expenses decreasedcapacity acquisition recovery variance is primarily due to a decrease in the average market price of purchased power.
2008 Compared to 2007
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysiscessation of the changecapacity acquisition rider to recover expenses incurred because those costs are recovered in net revenue comparing 2008 to 2007.base rates effective July 2010.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $1,110.6
|
Rider revenue | | 13.6 |
Purchased power capacity | | 4.8 |
Volume/weather | | (14.6) |
Other | | 3.5 |
2008 net revenue | | $1,117.9
|
The ridernet wholesale revenue variance is primarily due to an Energy Efficiency rider which became effective in November 2007. The establishment of the rider results in an increase in rider revenuelower margins on co-owner contracts and a corresponding increase in other operation and maintenance expense with no effect on net income. Also contributinglower wholesale billings to the variance was an increase in franchise tax rider revenue as a result of higher retail revenues. The corresponding increase is in taxes other than income taxes, resulting in no effect on net income.
The purchased power capacity variance is primarilyaffiliate companies due to lower reserve equalization expenses.
The volume/weather variance is primarily due to the effect of less favorable weather on residential and commercial sales, during the billed and unbilled sales periods compared to 2007 and a 2.9% volume decrease in industrial sales, primarily in the wood industry and the small customer class. Billed electricity usage decreased 333 GWh in all sectors. See "Critical Accounting Estimates" below and Note 1 to the financial statements for further discussion of the accounting for unbilled revenues.
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues increased primarily due to:
· | an increase of $114 million in gross wholesale revenue due to an increase in the average price of energy available for resale sales and an increase in sales to affiliated customers; |
· | an increase of $106.1 million in production cost allocation rider revenues which became effective in July 2007 as a result of the System Agreement proceedings. As a result of the System Agreement proceedings, Entergy Arkansas also has a corresponding increase in deferred fuel expense for payments to other Entergy system companies such that there is no effect on net income. Entergy Arkansas makes payments over a seven-month period but collections from customers occur over a twelve-month period. The production cost allocation rider is discussed in Note 2 to the financial statements and the System Agreement proceedings are referenced below under "Federal Regulation"; and
|
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
· | an increase of $58.9 million in fuel cost recovery revenues due to changes in the energy cost recovery rider effective April 2008 and September 2008, partially offset by decreased usage. The energy cost recovery rider filings are discussed in Note 2 to the financial statements. |
The increase was partially offset by a decrease of $14.6 million related to volume/weather, as discussed above.
Fuel and purchased power expenses increased primarily due to an increase of $106.1 million in deferred System Agreement payments, as discussed above and an increasemore favorable weather-adjusted usage in the average market price of purchased power.residential sector.
Other Income Statement Variances
20092012 Compared to 2008
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the planned maintenance and refueling outage at ANO 1 which ended in December 2008 and the planned maintenance and refueling outage at ANO 2 which ended in September 2009.
Other operation and maintenance expenses decreased primarily due to:
· | the write off in the fourth quarter 2008 of $52 million of costs previously accumulated in Entergy Arkansas' storm reserve and $16 million of removal costs associated with the termination of a lease, both in connection with the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas's 2006 base rate case. The 2006 base rate case is discussed in more detail in Note 2 to the financial statements;
|
· | the capitalization in 2009 of $12.5 million of Ouachita service charges previously expensed in 2008; |
· | prior year storm damage charges as a result of several storms hitting Entergy Arkansas' service territory in 2008, including Hurricane Gustav and Hurricane Ike in the third quarter 2008. Entergy Arkansas discontinued regulatory storm reserve accounting beginning July 2007 as a result of the APSC order issued in Entergy Arkansas' rate case. As a result, non-capital storm expenses of $41 million were charged to other operation and maintenance expenses. In December 2008, $19.4 million of these storm expenses were deferred per an APSC order and were recovered through revenues in 2009; and |
· | a decrease of $10.8 million in payroll-related and benefits costs. |
The decrease was partially offset by the following:
· | an increase of $17.9 million due to higher fossil costs primarily due to a full year of Ouachita costs in 2009 and higher fossil plant outage costs in 2009; |
· | an increase of $14.4 million due to the reinstatement of storm reserve accounting effective January 2009; |
· | an increase of $9.6 million in nuclear expenses primarily due to increased nuclear labor and contract costs; |
· | an increase in legal expenses as a result of a reimbursement in April 2008 of $7 million of costs in connection with a litigation settlement; and |
· | an increase of $4.0 million in customer service costs primarily as a result of write-offs of uncollectible customer accounts. |
Depreciation and amortization expenses increased primarily due to an increase in plant in service.
Interest expense increased primarily due to an increase in long-term debt outstanding as a result of the issuance of $300 million of 5.40% Series first mortgage bonds in July 2008.
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
2008 Compared to 20072011
Other operation and maintenance expenses increased primarily due to:
| · | the write-offan increase of $14.8 million in compensation and benefits costs resulting from a decrease in the fourth quarter 2008 of $52 million of costs previously accumulateddiscount rate and changes in Entergy Arkansas's storm reservecertain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and $16 million of removal costs associated with the termination of a lease, both in connection with the December 2008 Arkansas Court of Appeals decision in Entergy Arkansas's 2006 base rate case. The 2006 base rate case is discussed in more detail in Note 211 to the financial statements;statements for further discussion of benefits costs;
|
| · | an increase of $16.8$13.9 million in fossil plant expenses dueenergy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income; |
| · | $13.3 million of costs incurred in 2012 related to the Ouachita plant acquisition in 2008;planned spin-off and merger of the Utility’s transmission business; and |
| · | an increase of $15$10.3 million in storm damage charges as a result of several storms hitting Entergy Arkansas' service territory in 2008, including Hurricane Gustav and Hurricane Ike in the third quarter 2008. Entergy Arkansas discontinued regulatory storm reserve accounting beginning July 2007 as a result of the APSC order issued in Entergy Arkansas' 2006 base rate case. As a result, non-capital stormnuclear generation expenses of $41 million were chargedprimarily due to other operation and maintenance expenses. In December 2008, $19.4 million of these storm expenses were deferred per an APSC order and will be recovered through revenues in 2009. See Note 2 for discussion of the APSC order.higher contract costs. |
The increase was partially offset by:by a decrease of $8.0 million in fossil-fueled generation expenses primarily due to higher plant outage costs in 2011 due to a greater scope of work.
· | a decrease of $8.9 million in payroll-related and benefits costs; |
· | a decrease of $8.3 million related to expenses in connection with the nuclear fleet alignment in 2007, which is discussed in more detail in Note 13 to the financial statements; and |
· | a reimbursement of $7 million of costs in connection with a litigation settlement. |
Nuclear refueling outage expenses increased primarily due to higher costs associated with the most recent outage as compared to the previous outages.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes resulting from higher assessments and an increase in local franchise taxes resulting from higher residential and commercial electric revenues compared to 2011. Franchise taxes have no effect on net income as these taxes are recovered through the franchise tax rider.
2011 Compared to 2010
Other operation and maintenance expenses increased primarily due to:
| · | an increase of $6.1 million in fossil-fueled generation costs due to higher fossil plant outage costs due to a greater scope of work in 2011; |
| · | an increase of $3.9 million in transmission and distribution maintenance work in 2011; |
| · | $3.5 million in contract costs due to the transition and implementation of joining the MISO RTO; and |
| · | an increase of $3 million in nuclear expenses primarily due to higher labor and contract costs caused by several factors. |
The increase was offset by a $7.5 million decrease in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense.
Depreciation and amortization expenses decreased primarily due to a decrease in depreciation rates as a result of higher residentialthe rate case settlement agreement approved by the APSC in June 2010.
Entergy Arkansas, Inc. and commercial revenueSubsidiaries
Management’s Financial Discussion and an increase in ad valorem taxes due to a higher millage rate and a higher 2008 assessment.Analysis
Depreciation and amortization expenses increasedOther income decreased primarily due to an increasethe investment gains on the ANO 1 and 2 decommissioning trust in plant2010, as discussed above in service.net revenue, and the carrying charges on storm restoration costs recorded in 2010 related to the January 2009 ice storm. See Note 2 to the financial statements for further discussion of the 2009 ice storm costs and Note 5 to the financial statements for a discussion of the August 2010 issuance of securitization bonds to finance these costs.
Interest expense decreased primarily due to the refinancing of debt at lower interest rates.
Income Taxes
The effective income tax rates for 2009, 2008,2012, 2011, and 20072010 were 55.0%, 67.2%38.4%. 44.6%, and 38.1%39.6%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2009 | | 2008 | | 2007 | | 2012 | | | 2011 | | | 2010 | |
| | | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | | $39,568 | | $212 | | $34,815 | | $ | 22,599 | | | $ | 106,102 | | | $ | 86,233 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | |
| | Operating activities | | 384,192 | | 460,251 | | 366,118 | |
| | Investing activities | | (281,512) | | (608,501) | | (290,130) | |
| | Financing activities | | (56,015) | | 187,606 | | (110,591) | |
| | Net increase (decrease) in cash and cash equivalents | | 46,665 | | 39,356 | | (34,603) | |
| Net cash provided by (used in): | | | | | | | | | | | | | |
| Operating activities | | | | 509,117 | | | | 564,124 | | | | 512,260 | |
| Investing activities | | | | (723,248 | ) | | | (503,524 | ) | | | (413,180 | ) |
| Financing activities | | | | 226,065 | | | | (144,103 | ) | | | (79,211 | ) |
| Net increase (decrease) in cash and cash equivalents | | | | 11,934 | | | | (83,503 | ) | | | 19,869 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | | $86,233 | | $39,568 | | $212 | | $ | 34,533 | | | $ | 22,599 | | | $ | 106,102 | |
Operating Activities
Net cash provided by operating activities decreased $55.0 million in 2012 compared to 2011 primarily due to the $156 million System Agreement bandwidth remedy payment made in January 2012 as a result of the payment required to implement the FERC’s remedy for the period June – December 2005, a decrease of $69.5 million in income tax refunds, and the $30.6 million refund, including interest, to AmerenUE, as discussed above. These decreases were partially offset by a decrease of $83.2 million in pension contributions and the increased recovery of fuel and purchased power costs, including partial recovery of the System Agreement bandwidth remedy payment made in January 2012. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Net cash provided by operating activities increased $51.9 million in 2011 compared to 2010 primarily due to income tax refunds of $90 million in 2011 compared to income tax payments of $66.4 million in 2010. In 2011, Entergy Arkansas received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds result from a decrease in 2010 taxable income from what was previously estimated because of the recognition of additional repair expenses for tax purposes associated with a tax accounting change filed in 2010 and from the reversal of temporary differences for which Entergy Arkansas previously made cash tax payments. Pension contributions decreased $16.6 million. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits funding. The increase was offset by under-recovery of fuel costs and $19 million in storm restoration spending resulting from the April 2011 storms which caused damage to Entergy Arkansas’s transmission and distribution lines, equipment poles, and other facilities.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Operating Activities
Cash flow from operations decreased $76.1 million in 2009 compared to 2008 primarily due to income tax payments of $1.4 million in 2009 compared to income tax refunds of $57.9 million in 2008 and an increase in storm spending in 2009, partially offset by a decrease of $14.1 million in pension contributions.
Cash flow from operations increased $94.1 million in 2008 compared to 2007 primarily due to income tax refunds of $57.9 million in 2008 compared to income tax payments of $21.9 million in 2007 and an increase in recovery of fuel costs, partially offset by storm restoration spending.
Investing Activities
Net cash flow used in investing activities decreased $327.0increased $219.7 million in 20092012 compared to 20082011 primarily due to the purchase of the Ouachita plantHot Spring Energy Facility for $210approximately $253 million in September 2008November 2012 and the sale of one-third of the plant for $75 million in 2009, decreases in nuclear construction expenditures resulting from various nuclear projects that occurred in 2008, and decreases in distribution and transmission construction expenditures resulting from Hurricane Gustav and Hurricane Ike in 2008.money pool activity. The decreaseincrease was partially offset by an increasefluctuations in distribution construction expenditures as a resultnuclear fuel activity because of an ice storm hitting Entergy Arkansas' service territoryvariations from year to year in the first quarter 2009.timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle. See Note 15 to the financial statements for a discussion of the purchase of Hot Spring Energy Facility.
Decreases in Entergy Arkansas’s receivable from the money pool are a source of cash flow, and Entergy Arkansas’s receivable from the money pool decreased by $9.3 million in 2012 compared to decreasing by $24.1 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash flow used in investing activities increased $318.4$90.3 million in 20082011 compared to 20072010 primarily due to:
| · | an increase of $66.3 million in nuclear fuel purchases primarily due to the purchase of nuclear fuel inventory from System Fuels because the Ouachita plant for $210 million in September 2008. See Note 15 toUtility companies will now purchase nuclear fuel throughout the financial statements for more details onnuclear fuel procurement cycle, rather than purchasing it from System Fuels at the acquisition; |
· | an increase in nuclear construction expenditures resulting from various nuclear projects in 2008; |
· | an increase in distribution and transmission construction expenditures in 2008 due to Hurricane Gustav and Hurricane Ike, as well as several storms hitting Entergy Arkansas' service territory in the first quartertime of 2008;refueling; and |
| · | $51 million in storm restoration spending resulting from the April 2011 storms which caused damage to Entergy Arkansas’s transmission and distribution lines, equipment poles, and other facilities; and |
| · | $30 million in transmission substation reliability work in 2011. |
The increase was partially offset by money pool activity.
Increases in Entergy Arkansas'Arkansas’s receivable from the money pool are a use of cash flow, and Entergy Arkansas'Arkansas’s receivable from the money pool increased by $16$12.6 million in 2008 compared to decreasing by $14.3 million in 2007. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries' need for external short-term borrowings.2010.
Financing Activities
Entergy Arkansas' financingFinancing activities used $56.0provided cash of $226.1 million of cash in 20092012 compared to providing $187.6using cash of $144.1 million in 20082011 primarily due to:
| · | the issuance of $300$200 million of 5.4%4.9% Series first mortgage bonds in July 2008;December 2012 and $60 million 2.62% Series K note by the nuclear fuel company variable interest entity in December 2012 compared to the issuance of $55 million 3.23% Series J note by the nuclear fuel company variable interest entity in June 2011; |
| · | a decrease of $107.8 million in common stock dividends paid in 2012; |
| · | the repayment, at maturity, of a $35 million 5.60% Series G note by the nuclear fuel company variable interest entity in September 2011; and |
| · | an increase in borrowings on the nuclear fuel company variable interest entity’s credit facility. |
Net cash used in financing activities increased $64.9 million in 2011 compared to 2010 primarily due to:
| · | the issuance of $23.4$575 million of first mortgage bonds by Entergy Arkansas and $124.1 million of storm cost recovery bonds by Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, in 2010 compared to the issuance of the $55 million Series J note by the nuclear fuel company variable interest entity in 2011; and |
| · | a decrease in borrowings on the nuclear fuel company variable interest entity’s credit facility. |
The increase was offset by:
| · | the retirement of $450 million of first mortgage bonds and $139.5 million of pollution control revenue bonds in 2010 compared to the retirement of the $35 million Series G note by the nuclear fuel company variable interest entity in 2011; and |
| · | a decrease of $55.6 million in common stock dividends paid in 2009; and2011. |
Decreases in Entergy Arkansas' payable to the money pool are a use of cash flow, and Entergy Arkansas' payable to the money pool decreased by $77.9 million in 2008.
Entergy Arkansas' financing activities provided $187.6 million of cash in 2008 compared to using $110.6 million in 2007 primarily due to the issuance of $300 million of 5.40% Series First Mortgage Bonds in July 2008 and a decrease of $156.7 million in common stock dividends paid in 2008, partially offset by money pool activity.
Decreases in Entergy Arkansas' payable to the money pool are a use of cash flow, and Entergy Arkansas' payable to the money pool decreased by $77.9 million in 2008 compared to increasing by $77.9 million in 2007.
See Note 5 to the financial statements for details of long-term debt.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Capital Structure
Entergy Arkansas'Arkansas’s capitalization is balanced between equity and debt, as shown in the following table.
| | | December 31, 2009 | | December 31, 2008 |
| | | | | |
| Net debt to net capital | | 52.8% | | 52.9% |
| Effect of subtracting cash from debt | | 1.2% | | 0.6% |
| Debt to capital | | 54.0% | | 53.5% |
| | | December 31, 2012 | | December 31, 2011 |
| | | | | |
| Debt to capital | | 56.0% | | 55.0% |
| Effect of excluding the securitization bonds | | (1.2%) | | (1.5%) |
| Debt to capital, excluding securitization bonds (1) | | 54.8% | | 53.5% |
| Effect of subtracting cash | | (0.4%) | | (0.3%) |
| Net debt to net capital, excluding securitization bonds (1) | | 54.4% | | 53.2% |
| (1) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Arkansas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and shareholders'common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas'Arkansas’s financial condition.
Uses of Capital
Entergy Arkansas requires capital resources for:
| · | construction and other capital investments; |
| · | debt and preferred stock maturities;maturities or retirements; |
| · | working capital purposes, including the financing of fuel and purchased power costs; and |
| · | dividend and interest payments. |
Following are the amounts of Entergy Arkansas'Arkansas’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:obligations.
| | | 2010 | | 2011-2012 | | 2013-2014 | | after 2014 | | Total | | | 2013 | | 2014-2015 | | 2016-2017 | | after 2017 | | Total | |
| | | (In Millions) | | (In Millions) |
| Planned construction and | | | | | | | | | | | | |
| capital investment (1) | | $399 | | $1,001 | | N/A | | N/A | | $1,400 | | |
| Planned construction and capital investment (1): | | Planned construction and capital investment (1): | | | | | | | | | |
| Generation | | | $102 | | $344 | | N/A | | N/A | | $446 | |
| Transmission | | | 93 | | 303 | | N/A | | N/A | | 396 | |
| Distribution | | | 146 | | 281 | | N/A | | N/A | | 427 | |
| Other | | | 43 | | 88 | | N/A | | N/A | | 131 | |
| Total | | | $384 | | $1,016 | | N/A | | N/A | | $1,400 | |
| Long-term debt (2) | | $178 | | $152 | | $429 | | $1,841 | | $2,600 | | | $416 | | $216 | | $310 | | $2,529 | | $3,471 | |
| Capital lease payments | | $- | | $- | | $- | | $1 | | $1 | | | $0.2 | | $0.4 | | $- | | $- | | $0.6 | |
| Operating leases | | $21 | | $40 | | $33 | | $27 | | $121 | | | $28 | | $55 | | $20 | | $4 | | $107 | |
| Purchase obligations (3) | | $662 | | $1,017 | | $948 | | $2,177 | | $4,804 | | | $684 | | $1,175 | | $549 | | $1,858 | | $4,266 | |
| Nuclear fuel lease obligations (4) | | $73 | | $102 | | N/A | | N/A | | $175 | | |
| (1) | Includes approximately $193$252 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Arkansas, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
(4) | It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, Entergy Arkansas must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. |
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In addition, Entergy Arkansas currently expects to contribute approximately $73.1$34.9 million to its pension plans and approximately $21.6$26.7 million to other postretirement plans in 2010;2013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the2013. See "Critical Accounting Estimates – Qualified Pension Protection Actand Other Postretirement Benefits" below for a discussion of 2006 rules, effective for the 2008 plan yearqualified pension and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Arkansas’ pension contributions in the future.other postretirement benefits funding.
Also in addition to the contractual obligations, Entergy Arkansas has $178.1$2.5 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
The planned capital investment estimate for Entergy Arkansas also reflects capital required to support existing business and customer growth. The above amounts include approximately $420 million for installation of scrubbers and low NOx burners at Entergy Arkansas' White Bluff coal plant, which is discussed below. Entergy Arkansas continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis.
White Bluff Coal Plant Project
In June 2005 the EPA issued final Best Available Retrofit Control Technology (BART) regulations that could potentially result in a requirement to install SO2 pollution control technology on certain of Entergy's coal and oil generation units. The rule leaves certain BART determinations to the states. The Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the Clean Air Visibility Rule. The ADEQ determined that Entergy Arkansas' White Bluff power plant affects a Class I Area visibility and will be subject to the EPA's presumptive BART requirements to install scrubbers and low NOx burners. Under current regulations, the scrubbers would have to be operational by October 2013. Entergy filed a petition in December 2009 with the Arkansas Pollution Control and Ecology Commission requesting a variance from this deadline, however, because the EPA has not approved Arkansas' Regional Haze SIP and the EPA has recently expressed concerns about Arkansas' Regional Haze SIP and questioned the appropriateness of issuing an air permit prior to that approval. Entergy Arkansas' petition requests that, consistent with federal law, the compliance deadline be changed to as expeditiously as practicable, but in no event later than five years after EPA approval of the Arkansas Regional Haze SIP. The Arkansas Pollution Control and Ecology (PC&E) Commission adopted a procedural schedule that includes a public hearing and a comment period ending in March 2010 with the expectation that the variance could be considered at the Commission's March 26, 2010 meeting. The timeline for EPA action on the Arkansas Regional Haze SIP is uncertain at this time.
In March 2009, Entergy Arkansas made a filing with the APSC seeking a declaratory order that the White Bluff project is in the public interest. In May 2009 the APSC Staff filed a motion requesting that the APSC require Entergy Arkansas to file testimony on several issues. In December 2009, in response to the EPA concerns regarding Arkansas' Regional Haze SIP, the APSC suspended the procedural schedule in the proceeding.
Currently, the White Bluff project is suspended, but the latest conceptual cost estimate indicated that Entergy Arkansas' share of the project could cost approximately $465 million. The plant would continue to operate during construction, although an outage would be necessary to complete the tie in of the scrubbers. Entergy continues to review potential environmental spending needs and financing alternatives for any such spending, and future spending estimates could change based on the results of this continuing analysis.
Ouachita Power Plant
Entergy Arkansas filed with the APSC in September 2007 for its approval of the Ouachita plant acquisition, including full cost recovery. In June 2008 the APSC approved Entergy Arkansas' acquisition of the Ouachita plant and approved recovery of the acquisition and ownership costs through a rate rider. The APSC also approved the planned sale of one-third of the capacity and energy to Entergy Gulf States Louisiana. Entergy Arkansas purchased the Ouachita plant in September 2008.
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
In August 2008, the LPSC issued an order approving an uncontested settlement between Entergy Gulf States Louisiana and the LPSC Staff authorizing Entergy Gulf States Louisiana's purchase, under a life-of-unit agreement, of one-third of the capacity and energy from the 789 MW Ouachita power plant. The LPSC's approval was subject to certain conditions, including a study to determine the costs and benefits of Entergy Gulf States Louisiana exercising an option to purchase one-third of the plant (Unit 3) from Entergy Arkansas. In April 2009, Entergy Gulf States Louisiana made a filing with the LPSC seeking approval of Entergy Gulf States Louisiana exercising its option to convert its purchased power agreement into the ownership interest in Unit 3 and a one-third interest in the Ouachita common facilities. In September 2009 the LPSC, pursuant to an uncontested settlement, approved the acquisition and a cost recovery mechanism. Entergy Gulf States Louisiana purchased Unit 3 and a one-third interest in the Ouachita common facilities for $75 million in November 2009.
Entergy'sEntergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, environmental compliance, andbusiness restructuring, changes in project plans, the ability to access capital.capital, and the outcome of Entergy Arkansas’s exit from the System Agreement (which is discussed in “System Agreement” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis). Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Arkansas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly. Entergy Arkansas'Arkansas’s long-term debt indentures restrictindenture restricts the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2009,2012, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $461.6$394.9 million.
Sources of Capital
Entergy Arkansas'Arkansas’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt or preferred stock issuances; and |
| · | bank financing under new or existing facilities. |
Entergy Arkansas may refinance, redeem, or redeemotherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Arkansas require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in Entergy Arkansas'Arkansas’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
In April 2009, Entergy Arkansas renewed its credit facility through April 2010 in the amount of $88 million. There were no outstanding borrowings under the Entergy Arkansas credit facility as of December 31, 2009.
Entergy Arkansas'Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:years.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $28,859 | | $15,991 | | ($77,882) | | $16,109 |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $8,035 | | $17,362 | | $41,463 | | $28,859 |
In May 2007, $1.8 million of Entergy Arkansas' receivable from the money pool was replaced by a note receivable from Entergy New Orleans. See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Entergy Arkansas has credit facilities in the amount of $20 million and $150 million scheduled to expire in April 2013 and March 2017, respectively. No borrowings were outstanding under the credit facilities as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Arkansas nuclear fuel company variable interest entity has a credit facility in the amount of $85 million scheduled to expire in July 2013. As of December 31, 2012, $36.7 million was outstanding on the credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas has obtained short-term borrowing authorization from the FERC under which it may borrow through October 2011,2013, up to the aggregate amount, at any one time outstanding, of $250 million. See Note 4 to the financial statements for further discussion of Entergy Arkansas'Arkansas’s short-term borrowing limits. Entergy Arkansas has also obtained an order from the APSC authorizing long-term securities issuances through December 2012.2015. Entergy Arkansas has also obtained long-term financing authorization from the FERC that extends through May 2013 for issuances by its nuclear fuel company variable interest entity.
In January 2013, Entergy Arkansas arranged for the issuance by (i) Independence County, Arkansas of $45 million of 2.375% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due January 2021, and (ii) Jefferson County, Arkansas of $54.7 million of 1.55% Pollution Control Revenue Refunding Bonds (Entergy Arkansas, Inc. Project) Series 2013 due October 2017, each of which series is secured by a separate series of non-interest bearing first mortgage bonds of Entergy Arkansas. The proceeds of these issuances were applied to the refunding of outstanding series of pollution control revenue bonds previously issued by the respective issuers.
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2006 Base Rate Filing
In August 2006, Entergy Arkansas filed with the APSC a request for a change in base rates. Entergy Arkansas requested a general base rate increase (using an ROE of 11.25%), which it subsequently adjusted to a request for a $106.5 million annual increase. In June 2007, after hearings on the filing, the APSC ordered Entergy Arkansas to reduce its annual rates by $5 million, and set a return on common equity of 9.9% with a hypothetical common equity level lower than Entergy Arkansas' actual capital structure. For the purpose of setting rates, the APSC disallowed a portion of costs associated with incentive compensation based on financial measures and all costs associated with Entergy's stock-based compensation plans. In addition, under the terms of the APSC's decision, the order eliminated storm reserve accounting and set an amount of $14.4 million in base rates to address storm restoration costs, regardless of the actual annual amount of future restoration costs. The APSC's June 2007 decision left Entergy Arkansas with no mechanism to recover $52 million of costs previously accumulated in Entergy Arkansas' storm reserve and $18 million of removal costs associated with the termination of a lease.
The APSC denied Entergy Arkansas' request for rehearing of its June 2007 decision, and the base rate change was implemented August 29, 2007, effective for bills rendered after June 15, 2007. In December 2008 the Arkansas Court of Appeals upheld almost all aspects of the APSC decision. After considering the progress of the proceeding in light of the decision of the Court of Appeals, Entergy Arkansas recorded in the fourth quarter 2008 an approximately $70 million charge to earnings, on both a pre- and after-tax basis because these are primarily flow-through items, to recognize that the regulatory assets associated with the storm reserve costs, lease termination removal costs, and stock-based compensation are no longer probable of recovery. In April 2009 the Arkansas Supreme Court denied Entergy Arkansas' petition for review of the Court of Appeals decision.
2009 Base Rate Filing
OnIn September 4, 2009, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. Entergy Arkansas requestedIn June 2010 the APSC approved a $223.2settlement and subsequent compliance tariffs that provide for a $63.7 million base rate increase, that would become effective infor bills rendered for the first billing cycle of July 2010. The filing reflects an 11.5%settlement provides for a 10.2% return on common equity using a projected capital structure, and proposes a formula rate plan mechanism. Proposed formula rate plan provisions include a +/- 25 basis point bandwidth,equity.
2013 Base Rate Filing
On December 31, 2012, in accordance with earnings outside the bandwidth reset to the 11.5% return on common equity midpoint and rates changing on a prospective basis depending on whetherrequirements of Arkansas law, Entergy Arkansas is overfiled with the APSC notice of its intent to file an application for a general change or under-earning. The proposed formula rate plan also includes a recovery mechanism for APSC-approved costs for additional capacity purchases or construction/acquisition of new transmission or generating facilities. Entergy Arkansas is also seeking an increasemodification in its annual storm damage accrualrates and tariffs no sooner than 60 days and no longer than 90 days from $14.4 million to $22.3 million. The APSC scheduled hearings in the proceeding beginning in May 2010.date of its notice.
Production Cost Allocation Rider
In its June 2007 decision on Entergy Arkansas' August 2006 rate filing, theThe APSC approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings. These costs cause an increase in Entergy Arkansas'Arkansas’s deferred fuel cost balance because Entergy Arkansas pays the costs over seven months but collects them from customers over twelve months. In December 2007,
See Note 2 to the APSC issued a subsequent order stating that terminationfinancial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement” for discussions of the rider would be subject to eighteen months advance notice by the APSC, which would occur following notice and hearing.System Agreement proceedings.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
See Entergy Corporation and Subsidiaries' "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement Proceedings" for a discussion of the System Agreement proceedings.
Energy Cost Recovery Rider
Entergy Arkansas'Arkansas’s retail rates include an energy cost recovery rider. In December 2007,rider to recover fuel and purchased energy costs in monthly bills. The rider utilizes prior calendar year energy costs and projected energy sales for the APSC issuedtwelve-month period commencing on April 1 of each year to develop an order stating that terminationenergy cost rate, which is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery, including carrying charges, of the energy cost for the prior calendar year. The energy cost recovery rider would be subject to eighteen months advance notice bytariff also allows an interim rate request depending upon the APSC, which would occur following noticelevel of over- or under-recovery of fuel and hearing.purchased energy costs.
In March 2009, Entergy Arkansas filed with the APSC its annual energy cost rate for the period April 2009 through March 2010. The filed energy cost rate decreased from $0.02456/kWh to $0.01552/kWh. The decrease was caused by the following: 1) all three of the nuclear power plants from which Entergy Arkansas obtains power, ANO 1 and 2 and Grand Gulf, had refueling outages in 2008, and the previous energy cost rate had been adjusted to account for the replacement power costs that would be incurred while these units were down; 2) Entergy Arkansas had a deferred fuel cost liability from over-recovered fuel costs at December 31, 2008, as compared to a deferred fuel cost asset from under-recovered fuel costs at December 31, 2007; offset by 3) an increase in the fuel and purchased power prices included in the calculation.
In August 2009, as provided for by its energy cost recovery rider, Entergy Arkansas filed with the APSC an interim revision to its energy cost rate. The revised energy cost rate is a decrease from $0.01552/kWh to $0.01206/kWh. The decrease was caused by a decrease in natural gas and purchased power prices from the levels used in setting the rate in March 2009. The interim revised energy cost rate went into effect for the first billing cycle of September 2009. In its order approving the new rate, the APSC ordered Entergy Arkansas to show cause why the rate should not be further reduced. In its September 14, 2009 response, Entergy Arkansas explained that it used the same methodology it had used in previous interim revisions, which is based on estimating what the rate would be in the next annual update based on the information known at the time. There has been no further activity in this proceeding.
APSC Investigations
In September 2005, Entergy Arkansas filed with the APSC an interim energy cost rate per the energy cost recovery rider, which provides for an interim adjustment should the cumulative over- or under-recovery for the energy period exceed 10 percent of the energy costs for that period. In early October 2005, the APSC initiated an investigation into Entergy Arkansas'Arkansas's interim energy cost recovery rate. The investigation is focused on Entergy Arkansas'Arkansas's 1) gas contracting, portfolio, and hedging practices; 2) wholesale purchases during the period; 3) management of the coal inventory at its coal generation plants; and 4) response to the contractual failure of the railroads to provide coal deliveries. In March 2006 the APSC extended its investigation to cover the costs included in Entergy Arkansas'Arkansas's March 2006 annual energy cost rate filing, and a hearing was held in the APSC energy cost recovery investigation in October 2006.
In January 2007, the APSC issued an order in its review of the energy cost rate. The APSC found that Entergy Arkansas failed to maintain an adequate coal inventory level going into the summer of 2005 and that Entergy Arkansas should be responsible for any incremental energy costs resulting from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas has since resolved litigation with the railroad regarding the delivery problems. The APSC staff was directed to perform an analysis with Entergy Arkansas'Arkansas’s assistance to determine the additional fuel and purchased energy costs associated with these findings and file the analysis within 60 days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas would be directed to refund that amount with interest to its customers as a credit on the energy cost recovery rider. Entergy Arkansas requested rehearing of the order. In March 2007, in order to allow further consideration by the APSC, the APSC granted Entergy Arkansas'Arkansas’s petition for rehearing and for stay of the APSC order.
In October 2008, Entergy Arkansas filed a motion to lift the stay and to rescind the APSC's January 2007 order in light of the arguments advanced in Entergy Arkansas'Arkansas’s rehearing petition and because the value for Entergy Arkansas'Arkansas’s customers obtained through the resolved railroad litigation is significantly greater than the incremental cost of actions identified by the APSC as imprudent. The APSC staff, the AEEC, and the Arkansas attorney general support the lifting of the stay but request additional proceedings. In December 2008 the APSC denied the motion to lift the stay pending resolution of Entergy Arkansas'Arkansas’s rehearing request and of the unresolved issues in the proceeding. The APSC ordered the
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
parties to submit their unresolved issues list in the pending proceeding, which the parties have done.did. In February 2010 the APSC denied Entergy Arkansas'Arkansas’s request for rehearing, and scheduledheld a hearing forin September 2010 to determine the amount of damages, if any, that should be assessed against Entergy Arkansas. A decision is pending. Entergy Arkansas expects the amount of damages, if any, to have an immaterial effect on its results of operations, financial position, or cash flows.
The APSC also established a separate docket to consider the resolved railroad litigation, and in February 2010 it established a procedural schedule that concludesconcluded with testimony through September 2010. TheTestimony has been filed and the APSC may set a hearingwill decide the case based on the record in a future order, if necessary.the proceeding, including the prefiled testimony.
Storm Cost Recovery
Entergy Arkansas Storm Reserve Accounting
The APSC's June 2007 order in Entergy Arkansas' base rate proceeding eliminated storm reserve accounting for Entergy Arkansas. In March 2009 a law was enacted in Arkansas that requires the APSC to permit storm reserve accounting for utilities that request it. Entergy Arkansas filed its request with the APSC, and has reinstated storm reserve accounting effective January 1, 2009. A hearing on Entergy Arkansas' request is scheduled for March 2010.
Entergy Arkansas January 2009 Ice Storm
In January 2009, a severe ice storm caused significant damage to Entergy Arkansas'Arkansas’s transmission and distribution lines, equipment, poles, and other facilities. On January 30, 2009, the APSC issued an order inviting and encouraging electric public utilities to file specific proposals for the recovery of extraordinary storm restoration expenses associated with the ice storm. On February 16, 2009, Entergy Arkansas filed a request with the APSC for an accounting order authorizing deferral of the operating and maintenance cost portion of Entergy Arkansas' ice storm restoration costs pending their recovery. The APSC issued such an order in March 2009 subject to certain conditions, including that if Entergy Arkansas seeks to recover the deferred costs, those costs will be subject to investigation for whether they are incremental, prudent, and reasonable. A law was enacted in April 2009 in Arkansas that authorizes securitization of storm damage restoration costs. On February 1,In June 2010 Entergy Arkansas requestedthe APSC issued a financing order to issue approximately $127.5 million inauthorizing the issuance of storm cost recovery bonds, which includedincluding carrying costs of $11.7$11.5 million and $4.6 million of up-front financing costscosts. In August 2010, Entergy Arkansas Restoration Funding, LLC, a company wholly-owned and consolidated by Entergy Arkansas, issued $124.1 million of storm cost recovery bonds. See Note 5 to paythe financial statements for ice storm restoration because Entergy Arkansas' analysis demonstrates retail customers will benefit from lower costs using securitization. The APSC has established a procedural schedule that includes a hearing in April 2010 and states that the APSC will issue its final order by June 15, 2010. Entergy Arkansas' September 2009 general rate filing also requested recoveryadditional discussion of the January 2009 ice storm costs over 10 years if it was expected that securitization would not produce lower costs for customers, and Entergy Arkansas will remove this request if the APSC approves securitization.
Co-Owner-Initiated Proceeding at the FERC
In October 2004, Arkansas Electric Cooperative Corporation (AECC) filed a complaint at the FERC against Entergy Arkansas relating to a contract dispute over the pricing of substitute energy at the co-owned Independence and White Bluff coal plants. The main issue in the case related to the consequences under the governing contracts when the dispatchissuance of the coal units is constrained due to system operating conditions. A hearing was held on the AECC complaint and an ALJ Initial Decision was issued in January 2006 in which the ALJ found AECC's claims to be without merit. On October 25, 2006, the FERC issued its order in the proceeding. In the order, the FERC reversed the ALJ's findings. Specifically, the FERC found that the governing contracts do not recognize the effects of dispatch constraints on the co-owned units. The FERC explained that for over twenty-three years the course of conduct of the parties was such that AECC received its full entitlement to the two coal units, regardless of any reduced output caused by system operating constraints. Based on the order, Entergy Arkansas is required to refund to AECC all excess amounts billed to AECC as a result of the system operating constraints. The FERC denied Entergy Arkansas' requeststorm cost recovery bonds.
Entergy Arkansas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Entergy Arkansas December 2012 Winter Storm
In December 2012, a severe winter storm consisting of ice, snow, and high winds caused significant damage to Entergy Arkansas’s distribution lines, equipment, poles, and other facilities. Total restoration costs for rehearingthe repair and/or replacement of Entergy Arkansas’s electrical facilities in areas damaged from the winter storm are estimated to be in the range of $55 million to $65 million. Entergy Arkansas recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Arkansas recorded corresponding regulatory assets of approximately $21 million and construction work in progress of approximately $37 million. Entergy Arkansas recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Arkansas has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Arkansas refunded $22.1 million (including interest)is unable to AECCpredict with certainty the degree of success it may have in September 2007.its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery. Entergy Arkansas had previously recordedplans to present a cost recovery proposal to the APSC in a base rate case filing in March 2013.
Opportunity Sales Proceeding
In June 2009, the LPSC filed a complaint requesting that the FERC determine that certain of Entergy Arkansas’s sales of electric energy to third parties: (a) violated the provisions of the System Agreement that allocate the energy generated by Entergy System resources, (b) imprudently denied the Entergy System and its ultimate consumers the benefits of low-cost Entergy System generating capacity, and (c) violated the provision of the System Agreement that prohibits sales to third parties by individual companies absent an offer of a right-of-first-refusal to other Utility operating companies. The LPSC’s complaint challenges sales made beginning in 2002 and requests refunds. On July 20, 2009, the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the merits without hearing because the LPSC has failed to meet its burden of showing any violation of the System Agreement and failed to produce any evidence of imprudent action by the Entergy System. In their response the Utility operating companies explained that the System Agreement clearly contemplates that the Utility operating companies may make sales to third parties for their own account, subject to the requirement that those sales be included in the load (or load shape) for the estimatedapplicable Utility operating company. The response further explains that the FERC already has determined that Entergy Arkansas’s short-term wholesale sales did not trigger the “right-of-first-refusal” provision of the System Agreement. While the D.C. Circuit recently determined that the “right-of-first-refusal” issue was not properly before the FERC at the time of its earlier decision on the issue, the LPSC has raised no additional claims or facts that would warrant the FERC reaching a different conclusion.
The LPSC filed direct testimony in the proceeding alleging, among other things, (1) that Entergy violated the System Agreement by permitting Entergy Arkansas to make non-requirements sales to non-affiliated third parties rather than making such energy available to the other Utility operating companies’ customers; and (2) that over the period 2000 - 2009, these non-requirements sales caused harm to the Utility operating companies’ customers and these customers should be compensated for this harm by Entergy. In subsequent testimony the LPSC modified its original damages claim in favor of quantifying damages by re-running intra-system bills. The Utility operating companies believe the LPSC's allegations are without merit. A hearing in the matter was held in August 2010.
In December 2010, the ALJ issued an initial decision. The ALJ found that the System Agreement allowed for Entergy Arkansas to make the sales to third parties but concluded that the sales should be accounted for in the same manner as joint account sales. The ALJ concluded that “shareholders” should make refunds of the damages to the Utility operating companies, along with interest. Entergy disagreed with several aspects of the ALJ’s initial decision and in January 2011 filed with the FERC exceptions to the decision.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The FERC issued a decision in June 2012 and held that, while the System Agreement is ambiguous, it does provide authority for individual Utility operating companies to make opportunity sales for their own account and Entergy Arkansas made and priced these sales in good faith. The FERC found, however, that the System Agreement does not provide authority for an individual Utility operating company to allocate the energy associated with such opportunity sales as part of its load, but provides a different allocation authority. The FERC further found that the after-the-fact accounting methodology used to allocate the energy used to supply the sales was inconsistent with the System Agreement. Quantifying the effect of this refund. In January 2010the FERC’s decision will require re-running intra-system bills for a ten-year period, and the FERC issued anin its decision established further hearing procedures to determine the calculation of the effects. In July 2012, Entergy and the LPSC filed requests for rehearing of the FERC’s June 2012 decision, which are pending with the FERC.
As required by the procedural schedule established in the calculation proceeding, Entergy filed its direct testimony that included a proposed illustrative re-run, consistent with the directives in FERC’s order, conditionally acceptingof intra-system bills for 2003, 2004, and 2006, the refund report and ordering further refunds, notingthree years with the highest volume of opportunity sales. Entergy’s proposed illustrative re-run of intra-system bills shows that the refund period should have included the period July 1, 2004 through December 23, 2004.potential cost for Entergy Arkansas had previously recorded a provisionwould be up to $12 million for the estimated effectyears 2003, 2004, and 2006, and the potential benefit would be significantly less than that for each of this refund.the other Utility operating companies. Entergy’s proposed illustrative rerun of the intra-system bills also shows an offsetting potential benefit to Entergy Arkansas for the years 2003, 2004, and 2006 resulting from the effects of the FERC’s order on System Agreement Service Schedules MSS-1, MSS-2, and MSS-3, and the potential offsetting cost would be significantly less than that for each of the other Utility operating companies. Entergy provided to the LPSC an illustrative intra-system bill recalculation as specified by the LPSC for the years 2003, 2004, and 2006, and the LPSC then filed answering testimony in December 2012. In its testimony the LPSC claims that the damages that should be paid by Entergy Arkansas to the Utility operating company’s customers for 2003, 2004, and 2006 are $42 million to Entergy Gulf States, Inc., $7 million to Entergy Louisiana, $23 million to Entergy Mississippi, and $4 million to Entergy New Orleans; and that Entergy Arkansas “shareholders” should pay Entergy Arkansas customers $34 million. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. A hearing is scheduled for May 2013, and the ALJ’s initial decision on the calculation of the effects is due by August 28, 2013.
Federal Regulation
System Agreement Proceedings
See "“Independent Coordinator of Transmission”, “System Agreement Proceedings"”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries Management’s Financial Discussion and Analysis for a discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.
Transmission
See "Independent Coordinator of Transmission" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for further discussion.
Utility Restructuring
In April 1999, the Arkansas legislature enacted Act 1556, the Arkansas Electric Consumer Choice Act, providing for competition in the electric utility industry through retail open access. In December 2001, the APSC recommended to the Arkansas General Assembly that legislation be enacted during the 2003 legislative session to either repeal Act 1556 or further delay retail open access until at least 2010. In February 2003, the Arkansas legislature voted to repeal Act 1556 and the repeal was signed into law by the governor.these topics.
Nuclear Matters
Entergy Arkansas owns and operates, through an affiliate, the ANO 1 and ANO 2 nuclear power plants. Entergy Arkansas is, therefore, subject to the risks related to owning and operating nuclear plants. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of either ANO 1 or ANO 2, Entergy Arkansas may be required to file with the APSC a rate mechanism to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials associated with components within the reactor coolant system. The issue is applicable to ANO and is managed in accordance with industry standard practices and guidelines and includes in-service examinations, replacement and mitigation strategy. Several major modifications to the ANO units have been implemented to mitigate the susceptibility of large bore dissimilar metal welds. In addition, a replacement reactor vessel head has been fabricated for ANO 2.2 and is onsite. Routine inspections of the existing ANO 2 reactor vessel head have identified no significant material degradation issues for that component. These inspections will continue at planned refueling outages. Timing for installation of the new reactor vessel head will be based on the results of future inspection efforts.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy Arkansas'Arkansas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Arkansas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated. See "Uses of Capital" above for a discussion of the project to install scrubbers and low NOx burners at Entergy Arkansas' White Bluff coal plant, which under current environmental regulations must be operational by September 2013.
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy Arkansas'Arkansas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Arkansas'Arkansas’s financial position or results of operations.
Nuclear Decommissioning Costs
See "“Nuclear Decommissioning Costs"” in the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In the first quarter 2009, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and 2 as a result of a revised decommissioning cost study. The revised estimates resulted in an $8.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Arkansas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| | | | | | | |
| Discount rate | | (0.25%) | | $3,461 | | $44,172 |
| Rate of return on plan assets | | (0.25%) | | $1,934 | | $- |
| Rate of increase in compensation | | 0.25% | | $1,369 | | $7,694 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).
Actuarial Assumption | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | |
| | | | | | | |
| Discount rate | | (0.25%) | | $1,118 | | $11,528 |
| Health care cost trend | | 0.25% | | $1,690 | | $9,971 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Arkansas in 2012 was $53.1 million. Entergy Arkansas anticipates 2013 qualified pension cost to be approximately $63 million. Entergy Arkansas’s contributions to the pension trust were $37.2 million in 2012 and are currently estimated to be approximately $34.9 million in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013.
Total postretirement health care and life insurance benefit costs for Entergy Arkansas in 2012 were $18.1 million, including $5.8 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas expects 2013 postretirement health care and life insurance benefit costs to approximate $14.1 million, including $6.2 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Arkansas contributed $24.4 million to its other postretirement plans in 2012 and expects to contribute approximately $26.7 million in 2013.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
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To the Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Little Rock, Arkansas
We have audited the accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2012 and 2011, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 284 through 288 and applicable items in pages 57 through 204) for each of the three years in the period ended December 31, 2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. and Subsidiaries as of December 31, 2012 and 2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 27, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 27, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 2,127,004 | | | $ | 2,084,310 | | | $ | 2,082,447 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 480,464 | | | | 186,036 | | | | 378,699 | |
| Purchased power | | | 431,932 | | | | 659,464 | | | | 485,447 | |
| Nuclear refueling outage expenses | | | 47,103 | | | | 42,557 | | | | 41,800 | |
| Other operation and maintenance | | | 545,782 | | | | 511,592 | | | | 495,443 | |
| Decommissioning | | | 40,484 | | | | 38,064 | | | | 35,790 | |
| Taxes other than income taxes | | | 89,527 | | | | 82,847 | | | | 85,564 | |
| Depreciation and amortization | | | 222,734 | | | | 218,902 | | | | 232,085 | |
| Other regulatory charges (credits) - net | | | (38,406 | ) | | | (13,506 | ) | | | 1,603 | |
| TOTAL | | | 1,819,620 | | | | 1,725,956 | | | | 1,756,431 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 307,384 | | | | 358,354 | | | | 326,016 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 9,070 | | | | 7,660 | | | | 4,118 | |
| Interest and investment income | | | 15,169 | | | | 16,533 | | | | 46,363 | |
| Miscellaneous - net | | | (4,049 | ) | | | (4,172 | ) | | | (1,743 | ) |
| TOTAL | | | 20,190 | | | | 20,021 | | | | 48,738 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 82,860 | | | | 83,545 | | | | 91,598 | |
| Allowance for borrowed funds used during construction | | | (2,457 | ) | | | (2,826 | ) | | | (2,406 | ) |
| TOTAL | | | 80,403 | | | | 80,719 | | | | 89,192 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 247,171 | | | | 297,656 | | | | 285,562 | |
| | | | | | | | | | | | | |
| Income taxes | | | 94,806 | | | | 132,765 | | | | 112,944 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 152,365 | | | | 164,891 | | | | 172,618 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements | | | 6,873 | | | | 6,873 | | | | 6,873 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 145,492 | | | $ | 158,018 | | | $ | 165,745 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 152,365 | | | $ | 164,891 | | | $ | 172,618 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 357,913 | | | | 339,819 | | | | 347,587 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (67,482 | ) | | | 94,410 | | | | 100,071 | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | (30,786 | ) | | | (11,021 | ) | | | 34,214 | |
| Fuel inventory | | | (68 | ) | | | (11,190 | ) | | | (22,639 | ) |
| Accounts payable | | | (179,009 | ) | | | 160,983 | | | | (14,777 | ) |
| Prepaid taxes and taxes accrued | | | 178,688 | | | | 122,974 | | | | (63,188 | ) |
| Interest accrued | | | (1,463 | ) | | | 2,861 | | | | 426 | |
| Deferred fuel costs | | | 112,471 | | | | (148,274 | ) | | | 61,300 | |
| Other working capital accounts | | | 55,735 | | | | (3,855 | ) | | | 31,550 | |
| Provisions for estimated losses | | | 182 | | | | (2,330 | ) | | | (5,247 | ) |
| Other regulatory assets | | | (88,119 | ) | | | (215,841 | ) | | | (87,087 | ) |
| Pension and other postretirement liabilities | | | 75,725 | | | | 123,156 | | | | (32,496 | ) |
| Other assets and liabilities | | | (57,035 | ) | | | (52,459 | ) | | | (10,072 | ) |
| Net cash flow provided by operating activities | | | 509,117 | | | | 564,124 | | | | 512,260 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (361,858 | ) | | | (382,776 | ) | | | (291,267 | ) |
| Allowance for equity funds used during construction | | | 12,441 | | | | 9,607 | | | | 4,118 | |
| Nuclear fuel purchases | | | (215,968 | ) | | | (148,657 | ) | | | (82,371 | ) |
| Proceeds from sale of nuclear fuel | | | 96,700 | | | | - | | | | - | |
| Proceeds from sale of equipment | | | - | | | | - | | | | 2,489 | |
| Proceeds from nuclear decommissioning trust fund sales | | | 144,275 | | | | 125,408 | | | | 367,266 | |
| Investment in nuclear decommissioning trust funds | | | (154,608 | ) | | | (140,724 | ) | | | (400,832 | ) |
| Payment for purchase of plant | | | (253,043 | ) | | | - | | | | - | |
| Change in money pool receivable - net | | | 9,327 | | | | 24,101 | | | | (12,604 | ) |
| Changes in other investments - net | | | - | | | | - | | | | 2,415 | |
| Investment in affiliates | | | - | | | | 10,994 | | | | - | |
| Remittances to transition charge account | | | (15,613 | ) | | | (15,650 | ) | | | (2,412 | ) |
| Payments from transition charge account | | | 15,099 | | | | 14,173 | | | | - | |
| Other | | | - | | | | - | | | | 18 | |
| Net cash flow used in investing activities | | | (723,248 | ) | | | (503,524 | ) | | | (413,180 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 252,347 | | | | 54,743 | | | | 684,851 | |
| Retirement of long-term debt | | | (12,230 | ) | | | (45,310 | ) | | | (589,500 | ) |
| Changes in credit borrowings - net | | | 2,821 | | | | (28,863 | ) | | | 5,711 | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (10,000 | ) | | | (117,800 | ) | | | (173,400 | ) |
| Preferred stock | | | (6,873 | ) | | | (6,873 | ) | | | (6,873 | ) |
| Net cash flow provided by (used in) financing activities | | | 226,065 | | | | (144,103 | ) | | | (79,211 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 11,934 | | | | (83,503 | ) | | | 19,869 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 22,599 | | | | 106,102 | | | | 86,233 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 34,533 | | | $ | 22,599 | | | $ | 106,102 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 79,271 | | | $ | 75,650 | | | $ | 85,639 | |
| Income taxes | | $ | (20,480 | ) | | $ | (89,994 | ) | | $ | 66,403 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 9,597 | | | $ | 4,712 | |
| Temporary cash investments | | | 24,936 | | | | 17,887 | |
| Total cash and cash equivalents | | | 34,533 | | | | 22,599 | |
| Securitization recovery trust account | | | 4,403 | | | | 3,890 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 98,036 | | | | 90,940 | |
| Allowance for doubtful accounts | | | (28,343 | ) | | | (26,155 | ) |
| Associated companies | | | 67,277 | | | | 58,030 | |
| Other | | | 71,956 | | | | 66,838 | |
| Accrued unbilled revenues | | | 72,902 | | | | 70,715 | |
| Total accounts receivable | | | 281,828 | | | | 260,368 | |
| Accumulated deferred income taxes | | | 72,196 | | | | - | |
| Deferred fuel costs | | | 97,305 | | | | 209,776 | |
| Fuel inventory - at average cost | | | 48,975 | | | | 48,889 | |
| Materials and supplies - at average cost | | | 148,682 | | | | 143,343 | |
| Deferred nuclear refueling outage costs | | | 38,410 | | | | 49,047 | |
| System agreement cost equalization | | | - | | | | 36,800 | |
| Prepayments and other | | | 10,586 | | | | 8,562 | |
| TOTAL | | | 736,918 | | | | 783,274 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Decommissioning trust funds | | | 600,578 | | | | 541,657 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 1,671 | | | | 1,677 | |
| Other | | | 41,182 | | | | 3,182 | |
| TOTAL | | | 643,431 | | | | 546,516 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 8,693,659 | | | | 8,079,732 | |
| Property under capital lease | | | 1,154 | | | | 1,234 | |
| Construction work in progress | | | 205,982 | | | | 120,211 | |
| Nuclear fuel | | | 303,825 | | | | 272,593 | |
| TOTAL UTILITY PLANT | | | 9,204,620 | | | | 8,473,770 | |
| Less - accumulated depreciation and amortization | | | 4,104,882 | | | | 3,833,596 | |
| UTILITY PLANT - NET | | | 5,099,738 | | | | 4,640,174 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 80,751 | | | | 87,357 | |
| Other regulatory assets (includes securitization property of | | | | | |
| $93,238 as of December 31, 2012 and $105,762 as of | | | | | |
| December 31, 2011) | | | 1,221,636 | | | | 1,126,911 | |
| Other | | | 36,971 | | | | 27,980 | |
| TOTAL | | | 1,339,358 | | | | 1,242,248 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 7,819,445 | | | $ | 7,212,212 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 330,000 | | | $ | - | |
| Short-term borrowings | | | 36,735 | | | | 33,914 | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 39,288 | | | | 228,163 | |
| Other | | | 200,964 | | | | 138,054 | |
| Customer deposits | | | 85,198 | | | | 81,074 | |
| Taxes accrued | | | 214,969 | | | | 36,281 | |
| Accumulated deferred income taxes | | | 5,927 | | | | 124,267 | |
| Interest accrued | | | 28,418 | | | | 29,881 | |
| Other | | | 45,208 | | | | 23,305 | |
| TOTAL | | | 986,707 | | | | 694,939 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 1,829,281 | | | | 1,708,760 | |
| Accumulated deferred investment tax credits | | | 40,947 | | | | 42,939 | |
| Other regulatory liabilities | | | 143,901 | | | | 133,960 | |
| Decommissioning | | | 680,712 | | | | 640,228 | |
| Accumulated provisions | | | 5,822 | | | | 5,640 | |
| Pension and other postretirement liabilities | | | 614,805 | | | | 539,016 | |
| Long-term debt (includes securitization bonds of $101,547 as of | | | | | |
| December 31, 2012 and $113,761 as of December 31, 2011) | | | 1,793,895 | | | | 1,875,921 | |
| Other | | | 27,409 | | | | 10,335 | |
| TOTAL | | | 5,136,772 | | | | 4,956,799 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 116,350 | | | | 116,350 | |
| | | | | | | | | |
| COMMON EQUITY | | | | | | | | |
| Common stock, $0.01 par value, authorized 325,000,000 | | | | | |
| shares; issued and outstanding 46,980,196 shares in 2012 | | | | | |
| and 2011 | | | 470 | | | | 470 | |
| Paid-in capital | | | 588,444 | | | | 588,444 | |
| Retained earnings | | | 990,702 | | | | 855,210 | |
| TOTAL | | | 1,579,616 | | | | 1,444,124 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 7,819,445 | | | $ | 7,212,212 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | Common Equity | | | | |
| | | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Total | |
| | | (In Thousands) | | | | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 470 | | | $ | 588,444 | | | $ | 822,647 | | | $ | 1,411,561 | |
| Net income | | | - | | | | - | | | | 172,618 | | | | 172,618 | |
| Common stock dividends | | | - | | | | - | | | | (173,400 | ) | | | (173,400 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (6,873 | ) | | | (6,873 | ) |
| Balance at December 31, 2010 | | $ | 470 | | | $ | 588,444 | | | $ | 814,992 | | | $ | 1,403,906 | |
| Net income | | | - | | | | - | | | | 164,891 | | | | 164,891 | |
| Common stock dividends | | | - | | | | - | | | | (117,800 | ) | | | (117,800 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (6,873 | ) | | | (6,873 | ) |
| Balance at December 31, 2011 | | $ | 470 | | | $ | 588,444 | | | $ | 855,210 | | | $ | 1,444,124 | |
| Net income | | | - | | | | - | | | | 152,365 | | | | 152,365 | |
| Common stock dividends | | | - | | | | - | | | | (10,000 | ) | | | (10,000 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (6,873 | ) | | | (6,873 | ) |
| Balance at December 31, 2012 | | $ | 470 | | | $ | 588,444 | | | $ | 990,702 | | | $ | 1,579,616 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 2,127,004 | | | $ | 2,084,310 | | | $ | 2,082,447 | | | $ | 2,211,263 | | | $ | 2,328,349 | |
| Net Income | | $ | 152,365 | | | $ | 164,891 | | | $ | 172,618 | | | $ | 66,875 | | | $ | 47,152 | |
| Total assets | | $ | 7,819,445 | | | $ | 7,212,212 | | | $ | 6,751,368 | | | $ | 6,492,802 | | | $ | 6,568,213 | |
| Long-term obligations (1) | | $ | 1,910,245 | | | $ | 1,992,271 | | | $ | 1,946,494 | | | $ | 1,736,520 | | | $ | 1,800,735 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and preferred stock without sinking fund. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 766 | | | $ | 756 | | | $ | 773 | | | $ | 769 | | | $ | 756 | |
| Commercial | | | 472 | | | | 450 | | | | 441 | | | | 475 | | | | 463 | |
| Industrial | | | 439 | | | | 421 | | | | 415 | | | | 433 | | | | 461 | |
| Governmental | | | 20 | | | | 20 | | | | 20 | | | | 21 | | | | 21 | |
| Total retail | | | 1,697 | | | | 1,647 | | | | 1,649 | | | | 1,698 | | | | 1,701 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 320 | | | | 279 | | | | 302 | | | | 350 | | | | 416 | |
| Non-associated companies | | | 49 | | | | 96 | | | | 78 | | | | 102 | | | | 156 | |
| Other | | | 61 | | | | 62 | | | | 53 | | | | 61 | | | | 55 | |
| Total | | $ | 2,127 | | | $ | 2,084 | | | $ | 2,082 | | | $ | 2,211 | | | $ | 2,328 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 7,859 | | | | 8,229 | | | | 8,501 | | | | 7,464 | | | | 7,678 | |
| Commercial | | | 6,046 | | | | 6,051 | | | | 6,144 | | | | 5,817 | | | | 5,875 | |
| Industrial | | | 6,925 | | | | 7,029 | | | | 7,082 | | | | 6,376 | | | | 7,211 | |
| Governmental | | | 257 | | | | 275 | | | | 277 | | | | 269 | | | | 274 | |
| Total retail | | | 21,087 | | | | 21,584 | | | | 22,004 | | | | 19,926 | | | | 21,038 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 7,926 | | | | 6,893 | | | | 7,853 | | | | 9,980 | | | | 7,890 | |
| Non-associated companies | | | 1,093 | | | | 1,304 | | | | 850 | | | | 1,631 | | | | 2,159 | |
| Total | | | 30,106 | | | | 29,781 | | | | 30,707 | | | | 31,537 | | | | 31,087 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
ENTERGY GULF STATES LOUISIANA, L.L.C.
Plan to Spin Off the Utility’s Transmission Business
See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of this matter, including the planned retirement of debt and preferred securities.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy Gulf States Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Gulf States Louisiana’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $70 million. Entergy Gulf States Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. In January 2013, Entergy Gulf States Louisiana drew $65 million from its funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy Gulf States Louisiana recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Gulf States Louisiana recorded corresponding regulatory assets of approximately $17 million and construction work in progress of approximately $53 million. Entergy Gulf States Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Gulf States Louisiana has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Gulf States Louisiana is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Results of Operations
Net Income
2012 Compared to 2011
Net income decreased $42.6 million primarily due to lower net revenue and higher other operation and maintenance expenses. These items were partially offset by the $19.8 million income tax savings resulting from an IRS settlement in June 2012 related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing, which also resulted in a $27.7 million ($17 million net-of-tax) regulatory charge that reduced net revenue because the savings will be shared with customers. See Note 3 to the financial statements for additional discussion of the tax settlement and savings obligation.
2011 Compared to 2010
Net income increased $27.3 million primarily due to lower interest expense, a lower effective income tax rate, and lower other operation and maintenance expenses, offset by higher depreciation and amortization expenses.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Net Revenue
2012 Compared to 2011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2012 to 2011.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 933.4 | |
| Louisiana Act 55 financing savings obligation | | | (26.7 | ) |
| Retail electric price | | | (12.0 | ) |
| Volume/weather | | | (7.9 | ) |
| Net wholesale revenue | | | (7.8 | ) |
| Transmission revenue | | | (7.2 | ) |
| Other | | | (5.9 | ) |
| 2012 net revenue | | $ | 865.9 | |
The Louisiana Act 55 financing savings obligation results from a regulatory charge recorded in 2012 because Entergy Gulf States Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Note 3 to the financial statements for additional discussion of the tax settlement and savings obligation.
The retail electric price variance is primarily due to increased affiliate purchased power capacity costs recovered through base rates set in the annual formula rate plan mechanism. See Note 2 to the financial statements for additional discussion of Entergy Gulf States Louisiana’s formula rate plan.
The volume/weather variance is primarily due to the effect of milder weather, as compared to the prior period, on residential and commercial sales and the effects of the power outages caused by Hurricane Isaac.
The net wholesale revenue variance is primarily due to decreased sales volume to municipal and co-op customers and lower prices.
The transmission revenue variance is primarily due to a revision to transmission investment equalization billings under the System Agreement among the Utility operating companies (for the approximate period of 1996 – 2011) recorded in the fourth quarter 2011. See Note 2 to the financial statements for further discussion of the revision.
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)
Gross operating revenues decreased primarily due to a decrease of $203.8 million in gross wholesale revenues primarily due to a decrease in sales to affiliated customers, a decrease of $168.4 million in fuel cost recovery revenues primarily due to lower fuel rates, and a decrease of $59.3 million in rider revenues primarily due to higher System Agreement credits in 2012. See Note 2 to the financial statements for additional discussion of Entergy Gulf States Louisiana’s fuel and purchased power recovery mechanism.
Fuel and purchased power expenses decreased primarily due to:
| · | a decrease in the average market prices of purchased power and natural gas; and |
| · | a decrease in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers and lower fuel cost recovery revenues in 2012. See Note 2 to the financial statements for a discussion of the System Agreement proceedings. |
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
2011 Compared to 2010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2011 to 2010.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 933.6 | |
| Retail electric price | | | (20.1 | ) |
| Volume/weather | | | (5.2 | ) |
| Transmission revenue | | | 12.4 | |
| Fuel recovery | | | 14.8 | |
| Other | | | (2.1 | ) |
| 2011 net revenue | | $ | 933.4 | |
The retail electric price variance is primarily due to an increase in credits passed on to customers as a result of the Act 55 storm cost financing. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, including during the unbilled sales period. The decrease was partially offset by an increase of 62 GWh, or 0.3%, in billed electricity usage, primarily due to increased consumption by an industrial customer as a result of the customer’s cogeneration outage and the addition of a new production unit by the industrial customer.
The transmission revenue variance is primarily due to a revision to transmission investment equalization billings under the System Agreement among the Utility operating companies (for the approximate period of 1996 – 2011) recorded in the fourth quarter 2011. See Note 2 to the financial statements for further discussion of the revision.
The fuel recovery variance resulted primarily from an adjustment to deferred fuel costs in 2010. See Note 2 to the financial statements for a discussion of fuel recovery.
Fuel and purchased power expenses
Fuel and purchased power expenses increased primarily due to:
| · | an increase in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers; |
| · | an increase in natural gas fuel expense primarily due to increased generation; and |
| · | an increase in deferred fuel expense due to fuel and purchased power expense decreases in excess of lower fuel cost recovery revenues. |
The increase was offset by a decrease in the average market price of purchased power and decreased net area demand.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Other Income Statement Variances
2012 Compared to 2011
Other operation and maintenance expenses increased primarily due to:
| · | an increase of $10.4 million in nuclear generation expenses primarily due to higher labor costs, including higher contract labor; |
| · | an increase of $9.3 million in compensation and benefits costs primarily due to decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs; |
| · | $4.7 million of costs incurred in 2012 related to the planned spin-off and merger of the transmission business; and |
| · | an increase of $3.7 million in fossil-fueled generation expenses resulting primarily from increased plant outages and an increased scope of work as compared to the prior year. |
The increase was partially offset by:
| · | $5.8 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmissions costs (for the approximate period of 1996 – 2011) allocable to Entergy Gulf States Louisiana under the System Agreement; |
| · | the deferral, as approved by the LPSC and the FERC, of costs related to the transition and implementation of joining the MISO RTO, which reduced expenses by $4.2 million; and |
| · | several individually insignificant items. |
2011 Compared to 2010
Nuclear refueling outage expenses decreased primarily due to the amortization of lower expenses associated with the planned maintenance and refueling outage at River Bend in the first quarter 2011.
Other operation and maintenance expenses decreased primarily due to:
| · | a decrease of $6 million in fossil-fueled generation expenses primarily due to fewer outages and a reduced scope of work compared to 2010; and |
| · | a decrease of $4.2 million in compensation and benefits costs primarily resulting from an increase in the accrual for incentive-based compensation in 2010 and a decrease in stock option expense. |
The decrease was partially offset by an increase of $2.9 million in costs due to the transition and implementation of joining the MISO RTO, as well as several individually insignificant items.
Depreciation and amortization expenses increased primarily due to a revision in the second quarter 2010 related to depreciation on storm cost-related assets and an increase in plant in service. Recovery of the storm cost-related assets will now be through the Act 55 financing of storm costs as approved by the LPSC in June 2010. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
Interest expense decreased primarily due to:
| · | redemptions of first mortgage bonds of $68 million in June 2010 and $304 million in November 2010, partially offset by the issuance of first mortgage bonds of $250 million in October 2010. See Note 5 to the financial statements for a discussion of long-term debt; and |
| · | interest expense accrued in 2010 related to the expected result of the LPSC Staff audit of the fuel adjustment clause for the period 1995 through 2004. See Note 2 to the financial statements for a discussion of fuel recovery. |
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Income Taxes
The effective income tax rates were 24.9%, 30.8%, and 34.6% for 2012, 2011, and 2010, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Correction of Regulatory Asset for Income Taxes
See Note 2 to the financial statements for a discussion of the financial statement effects of a correction to Entergy Gulf States Louisiana’s regulatory asset for income taxes.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 24,845 | | | $ | 155,173 | | | $ | 144,460 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 346,208 | | | | 482,115 | | | | 726,130 | |
| Investing activities | | | (201,440 | ) | | | (267,262 | ) | | | (541,583 | ) |
| Financing activities | | | (133,927 | ) | | | (345,181 | ) | | | (173,834 | ) |
| Net increase (decrease) in cash and cash equivalents | | | 10,841 | | | | (130,328 | ) | | | 10,713 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 35,686 | | | $ | 24,845 | | | $ | 155,173 | |
Operating Activities
Net cash provided by operating activities decreased $135.9 million in 2012 compared to 2011 primarily due to income tax payments in 2012 of $89.2 million in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement compared to income tax refunds of $56.3 million in 2011. In 2012, Entergy Gulf States Louisiana no longer had a net operating loss carryover from prior years to reduce current taxable income. Also contributing to the decrease in cash flow was Hurricane Isaac storm restoration spending in 2012. In 2011, Entergy Gulf States Louisiana received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the reversal of temporary differences for which Entergy Gulf States Louisiana previously made cash tax payments.
The decrease was partially offset by:
| · | an increase in the recovery of fuel and purchased power costs due to System Agreement bandwidth remedy payments of $75 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June – December 2005. In the fourth quarter 2012, Entergy Gulf States Louisiana customers were credited $69.6 million. See Note 2 to the financial statements for a discussion of the System Agreement proceedings; and |
| · | a decrease of $13.7 million in pension contributions. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits. |
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Net cash provided by operating activities decreased $244 million in 2011 compared to 2010 primarily due to:
| · | proceeds of $240.3 million received from the LURC as a result of the Act 55 storm cost financings in 2010. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and |
| · | higher nuclear refueling outage spending at River Bend. River Bend had a refueling outage in 2011 and did not have one in 2010. |
The decrease was partially offset by an increase in income tax refunds of $39.5 million in 2011 compared to 2010. In 2011, Entergy Gulf States Louisiana received tax cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds resulted from the reversal of temporary differences for which Entergy Gulf States Louisiana previously made cash tax payments.
Investing Activities
Net cash used in investing activities decreased $65.8 million in 2012 compared to 2011 primarily due to:
| · | fluctuations in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; |
| · | $51 million in proceeds from the sale of a portion of Entergy Gulf States Louisiana’s investment in Entergy Holdings Company’s Class A preferred membership interests to a third party in 2012; and |
| · | a decrease in nuclear construction expenditures as a result of the River Bend refueling outage in 2011. River Bend had a refueling outage in 2011 and did not have one in 2012. |
The decrease was partially offset by:
| · | higher distribution construction expenditures due to Hurricane Isaac and increased reliability work performed in 2012; |
| · | an increase in fossil-fueled generation construction expenditures due to an increased scope of work in 2012; and |
| · | an increase in transmission construction expenditures due to increased transmission plant upgrades in 2012. |
Decreases in Entergy Gulf States Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Gulf States Louisiana’s receivable from the money pool decreased by $23.6 million in 2012 compared to decreasing by $39.4 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility operating companies’ need for external short-term borrowings.
Net cash used in investing activities decreased $274.3 million in 2011 compared to 2010 primarily due to:
| · | the investment in 2010 of $150.3 million in affiliate securities and the investment of $90.1 million in the storm reserve escrow account as a result of the Act 55 storm cost financings. See “Hurricane Gustav and Hurricane Ike” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and |
The decrease was partially offset by an increase in nuclear fuel purchases because River Bend had a refueling outage in 2011 and did not have one in 2010.
Decreases in Entergy Gulf States Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Gulf States Louisiana’s receivable from the money pool decreased by $39.4 million in 2011 compared to increasing by $12.9 million in 2010.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Financing Activities
Net cash used in financing activities decreased $211.3 million in 2012 compared to 2011 primarily due to a decrease of $187.8 million in common equity distributions and the issuance of $75 million 3.25% Series Q notes by the nuclear fuel company variable interest entity in July 2012, partially offset by:
| · | the repayment, at maturity, of $60 million 5.41% Series O notes by the nuclear fuel company variable interest entity in July 2012; |
| · | the redemption of $10.84 million of pollution control revenue bonds in 2012 compared to the redemption of $47.34 million of pollution control revenue bonds in 2011; and |
| · | payments of $29.4 million on credit borrowings in 2012 compared to an increase of $5.2 million in credit borrowings in 2011 against the nuclear fuel company variable interest entity credit facility. |
Net cash used in financing activities increased $171.3 million in 2011 compared to 2010 primarily due to an increase of $177.7 million in common equity distributions.
Capital Structure
Entergy Gulf States Louisiana’s capitalization is balanced between equity and debt, as shown in the following table.
| | | December 31, 2012 | | December 31, 2011 |
| | | | | |
| Debt to capital | | 52.3% | | 53.6% |
| Effect of subtracting cash | | (0.6%) | | (0.4%) |
| Net debt to net capital | | 51.7% | | 53.2% |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion. Capital consists of debt and member’s equity. Net capital consists of capital less cash and cash equivalents. Entergy Gulf States Louisiana uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana’s financial condition.
Uses of Capital
Entergy Gulf States Louisiana requires capital resources for:
| · | construction and other capital investments; |
| · | debt and preferred equity maturities or retirements; |
| · | working capital purposes, including the financing of fuel and purchased power costs; and |
| · | distribution and interest payments. |
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Gulf States Louisiana’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations.
| | 2013 | | 2014-2015 | | 2016-2017 | | after 2017 | | Total |
| | (In Millions) |
| Planned construction and capital investment (1): | | | | | | | |
| Generation | $79 | | $154 | | N/A | | N/A | | $233 |
| Transmission | 83 | | 99 | | N/A | | N/A | | 182 |
| Distribution | 76 | | 138 | | N/A | | N/A | | 214 |
| Other | 20 | | 44 | | N/A | | N/A | | 64 |
| Total | $258 | | $435 | | N/A | | N/A | | $693 |
| Long-term debt (2) | $153 | | $191 | | $237 | | $1,851 | | $2,432 |
| Operating leases | $12 | | $30 | | $18 | | $44 | | $104 |
| Purchase obligations (3) | $169 | | $289 | | $187 | | $197 | | $842 |
| (1) | Includes approximately $146 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Gulf States Louisiana, it primarily includes unconditional fuel and purchased power obligations. |
In addition to the contractual obligations given above, Entergy Gulf States Louisiana expects to contribute $11.2 million to its pension plans and $8.4 million to other postretirement plans in 2013 although the required pension contributions will not be known with more certainty until the January 1, 2013 valuations are completed by April 1, 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
Also, in addition to the contractual obligations, Entergy Gulf States Louisiana has $304.8 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
The planned capital investment estimate for Entergy Gulf States Louisiana reflects capital required to support existing business and customer growth. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Management provides more information on long-term debt maturities in Note 5 to the financial statements.
As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Gulf States Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Gulf States Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
New Nuclear Development
Entergy Gulf States Louisiana and Entergy Louisiana have been developing and are preserving a project option for new nuclear generation at River Bend. In the first quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and recognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company’s current participation level in the project.
In March 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. The testimony and legal briefs of the LPSC staff generally support the request of Entergy Gulf States Louisiana and Entergy Louisiana, although other parties filed briefs, without supporting testimony, in opposition to the request. At an evidentiary hearing in October 2011, Entergy Gulf States Louisiana, Entergy Louisiana, and the LPSC staff presented testimony in support of certification of activities to preserve an option for a new nuclear plant at River Bend. The ALJ recommended, however, that the LPSC decline the request of Entergy Gulf States Louisiana and Entergy Louisiana on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies improperly engaged in advanced preparation activities prior to certification. There has been no suggestion that the planning activities or costs incurred were imprudent. At its June 28, 2012 meeting the LPSC voted to uphold the ALJ’s decision and directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their anticipated, upcoming rate case filings, fully reserving the LPSC’s right to determine the recoverability of such costs in rates. On September 10, 2012, Entergy Gulf States Louisiana and Entergy Louisiana filed a petition for appeal and judicial review of the LPSC’s order with the Louisiana Nineteenth Judicial District Court. A schedule for the appeal has not been established. In their rate cases filed in February 2013, Entergy Gulf States Louisiana and Entergy Louisiana request recovery of their new nuclear generation development costs over a ten-year amortization period, with the costs included in rate base.
Sources of Capital
Entergy Gulf States Louisiana’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt or preferred membership interest issuances; and |
| · | bank financing under new or existing facilities. |
Entergy Gulf States Louisiana may refinance, redeem, or otherwise retire debt and preferred equity/membership interests prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred equity/membership interest issuances by Entergy Gulf States Louisiana require prior regulatory approval. Preferred equity/membership interest and debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. Entergy Gulf States Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Gulf States Louisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| ($7,074) | | $23,596 | | $63,003 | | $50,131 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Entergy Gulf States Louisiana has a credit facility in the amount of $150 million scheduled to expire in March 2017. No borrowings were outstanding under the credit facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Gulf States Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $85 million scheduled to expire in July 2013. No borrowings were outstanding on the variable interest entity credit facility as of December 31, 2012. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.
Entergy Gulf States Louisiana obtained short-term borrowing authorization from the FERC under which it may borrow through October 2013, up to the aggregate amount, at any one time outstanding, of $200 million. See Note 4 to the financial statements for further discussion of Entergy Gulf States Louisiana’s short-term borrowing limits. Entergy Gulf States Louisiana has also obtained an order from the FERC authorizing long-term securities issuances through July 2013. Entergy Gulf States Louisiana has also obtained long-term financing authorization from the FERC that extends through September 2014 for issuances by its nuclear fuel company variable interest entity.
In February 2013 the Entergy Gulf States Louisiana nuclear fuel company variable interest entity issued $70 million of 3.38% Series R notes due August 2020. The Entergy Gulf States Louisiana nuclear fuel company variable interest entity used the proceeds principally to purchase additional nuclear fuel.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Gulf States Louisiana’s service territory. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In October 2008, Entergy Gulf States Louisiana drew all of its $85 million funded storm reserve. On October 15, 2008, the LPSC approved Entergy Gulf States Louisiana’s request to defer and accrue carrying costs on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate.
Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Act 55 financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Act 55 financing savings to customers via a Storm Cost Offset rider.
In December 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financings are accomplished. In March and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States Louisiana’s and Entergy Louisiana's proposals under the Act 55 financings, which
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
includes a commitment to pass on to customers a minimum of $15.5 million and $27.75 million of customer benefits, respectively, through prospective annual rate reductions of $3.1 million and $5.55 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financings.
In July 2010, the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $244.1 million in bonds under Act 55. From the $240.3 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $90 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $150.3 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana used $150.3 million to acquire 1,502,643.04 Class B preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion. In the first quarter 2012, Entergy Gulf States Louisiana sold to a third party for $51 million a portion of its investment in Entergy Holdings Company’s Class A preferred membership interests.
Entergy Gulf States Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LCDA, and there is no recourse against Entergy Gulf States Louisiana in the event of a bond default. To service the bonds, Entergy Gulf States Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy Gulf States Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.
Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. All major permits and approvals required to begin construction have been obtained and construction is in progress.
Under the terms approved by the LPSC, costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans, if one is in effect when the project is placed in service; alternatively, Entergy Gulf States Louisiana and Entergy Louisiana must file rate cases approximately 12 months prior to the expected in-service date.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Gulf States Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Gulf States Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC is primarily responsible for approval of the rates charged to customers.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Retail Rates – Electric
In October 2009, the LPSC approved a settlement that resolved Entergy Gulf States Louisiana’s 2007 test year filing and provided for a formula rate plan for the 2008, 2009, and 2010 test years. 10.65% is the target midpoint return on equity for the formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). Entergy Gulf States Louisiana, effective with the November 2009 billing cycle, reset its rates to achieve a 10.65% return on equity for the 2008 test year. The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset was subject to refund pending review of the 2008 test year filing that was made in October 2009. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. In May 2010, Entergy Gulf States Louisiana and the LPSC staff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in a $0.8 million reduction in rates effective in the June 2010 billing cycle and a $0.5 million refund. At its May 19, 2010 meeting, the LPSC accepted the joint report.
In May 2010, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2009 test year. The filing reflected a 10.25% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to a NRC notification of a projected shortfall of decommissioning funding assurance. The filing also reflected a rate increase for incremental capacity costs. In July 2010 the LPSC approved a $7.8 million increase in the revenue requirement for decommissioning, effective September 2010. In August 2010, Entergy Gulf States Louisiana made a revised 2009 test year filing. The revised filing reflected a 10.12% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The revised filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously approved decommissioning revenue requirement, and (2) $25.2 million for capacity costs. The rates reflected in the revised filing became effective, beginning with the first billing cycle of September 2010. Entergy Gulf States Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in January 2011.
In May 2011, Entergy Gulf States Louisiana made a special formula rate plan rate implementation filing with the LPSC that implemented effective with the May 2011 billing cycle a $5.1 million rate decrease to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center by Entergy Louisiana. As a result of the closing of the acquisition and termination of the pre-acquisition power purchase agreement with Acadia, Entergy Gulf States Louisiana’s allocation of capacity related to this unit ended, resulting in a reduction in the additional capacity revenue requirement.
In May 2011, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2010 test year. The filing reflected an 11.11% earned return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing also reflected a $22.8 million rate decrease for incremental capacity costs. Entergy Gulf States Louisiana and the LPSC Staff subsequently filed a joint report that also stated that no cost of service rate change is necessary under the formula rate plan, and the LPSC approved it in October 2011.
In November 2011, the LPSC approved a one-year extension of Entergy Gulf States Louisiana’s formula rate plan. In May 2012, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2011 test year. The filing reflected an 11.94% earned return on common equity, which is above the earnings bandwidth and would indicate a $6.5 million cost of service rate decrease was necessary under the formula rate plan. The filing also reflected a $22.9 million rate decrease for incremental capacity costs. Subsequently, in August 2012, Entergy Gulf States Louisiana submitted a revised filing that reflected an earned return on common equity of 11.86% indicating a $5.7 million cost of service rate decrease is necessary under the formula rate plan. The
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
revised filing also indicates that a reduction of $20.3 million should be reflected in the incremental capacity rider. The rate reductions were implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change reduced Entergy Gulf States Louisiana’s revenues by approximately $8.7 million in 2012. Subsequently, in December 2012, Entergy Gulf States Louisiana submitted a revised evaluation report that reflects expected retail jurisdictional cost of $16.9 million for the first-year capacity charges for the purchase from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy. This rate change was implemented effective with the first billing cycle of January 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan to the 2011 test year, the LPSC required that a base rate case be filed by Entergy Gulf States Louisiana, and the required filing was made on February 15, 2013. Recognizing that the final structure of Entergy Gulf States Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to establish the appropriate level of rates for Entergy Gulf States Louisiana.
Under its primary request, Entergy Gulf States Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $28 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Under the alternative request contained in its filing, Entergy Gulf States Louisiana assumes that it has completed integration into MISO, but that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Gulf States Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $24 million; |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Gulf States Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
Retail Rates – Gas
In January 2013, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2012. The filing showed an earned return on common equity of 11.18 %, which results in a $43 thousand rate reduction. The sixty-day review and comment period for this filing remains open.
Related to the annual gas rate stabilization plan proceedings, the LPSC directed its staff to initiate an evaluation of the 10.5% allowed return on common equity for the Entergy Gulf States Louisiana gas rate stabilization plan. The LPSC directed that its staff should provide an analysis of the current return on equity and justification for any proposed changes to the return on equity. A hearing in the proceeding was held in November 2012. The ALJ issued a proposed recommendation in December 2012, finding that 9.4% is a more reasonable and appropriate rate of return on common equity. Entergy Gulf States Louisiana filed exceptions to the ALJ’s recommendation and an LPSC decision is pending.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
In January 2012, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2011. The filing showed an earned return on common equity of 10.48%, which is within the earnings bandwidth of 10.5%, plus or minus fifty basis points. In April 2012 the LPSC Staff filed its findings, suggesting adjustments that produced an 11.54% earned return on common equity for the test year and a $0.1 million rate reduction. Entergy Gulf States Louisiana accepted the LPSC Staff’s recommendations, and the rate reduction was effective with the first billing cycle of May 2012.
In January 2011, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2010. The filing showed an earned return on common equity of 8.84% and a revenue deficiency of $0.3 million. In March 2011 the LPSC Staff filed its findings, suggesting an adjustment that produced an 11.76% earned return on common equity for the test year and a $0.2 million rate reduction. Entergy Gulf States Louisiana implemented the $0.2 million rate reduction effective with the May 2011 billing cycle. The LPSC docket is now closed.
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points, resulting in no rate change. In April 2010, Entergy Gulf States Louisiana filed a revised evaluation report reflecting changes agreed upon with the LPSC Staff. The revised evaluation report also resulted in no rate change.
Fuel and purchased power cost recovery
In January 2003, the LPSC authorized its staff to initiate a proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit included a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 1995 through 2004. Entergy Gulf States Louisiana and the LPSC Staff reached a settlement to resolve the audit that requires Entergy Gulf States Louisiana to refund $18 million to customers, including the realignment to base rates of $2 million of SO2 costs. The ALJ held a stipulation hearing and in November 2011 the LPSC issued an order approving the settlement. The refund was made in the November 2011 billing cycle. Entergy Gulf States Louisiana had previously recorded provisions for the estimated outcome of this proceeding.
In December 2011, the LPSC authorized its staff to initiate another proceeding to audit the fuel adjustment clause filings of Entergy Gulf States Louisiana and its affiliates. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period 2005 through 2009. Discovery is in progress, but a procedural schedule has not been established.
Industrial and Commercial Customers
Entergy Gulf States Louisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States Louisiana’s industrial customer base. Entergy Gulf States Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Gulf States Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States Louisiana’s marketing efforts in retaining industrial customers.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Federal Regulation
See “Independent Coordinator of Transmission”, “System Agreement”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
Nuclear Matters
Entergy Gulf States Louisiana owns and, through an affiliate, operates the River Bend nuclear power plant. Entergy Gulf States Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
Environmental Risks
Entergy Gulf States Louisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Gulf States Louisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy’s financial position or results of operations.
Nuclear Decommissioning Costs
See “Nuclear Decommissioning Costs” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries’ Management’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Gulf States Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Entergy Arkansas, Inc.
Management's Financial Discussion and Analysis
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $2,199 | | $22,989 | | (0.25%) | | $1,808 | | $23,290 |
| Rate of return on plan assets | | (0.25%) | | $1,434 | | - | | (0.25%) | | $1,011 | | $- |
| Rate of increase in compensation | | 0.25% | | $1,055 | | $4,982 | | 0.25% | | $708 | | $4,256 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $876 | | $8,042 |
| Health care cost trend | | 0.25% | | $1,069 | | $5,659 | | 0.25% | | $1,322 | | $7,509 |
| Discount rate | | (0.25%) | | $594 | | $6,327 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy ArkansasGulf States Louisiana in 20092012 was $19.8 million. Entergy ArkansasGulf States Louisiana anticipates 20102013 qualified pension cost to be approximately $31.7$29.8 million. Entergy Arkansas'Gulf States Louisiana contributed $13.6 million to its pension plans in 2012 and estimates 2013 pension contributions to the pension trust were $24.8 million in 2009 and are currently estimated to be approximately $73.1 million in 2010;$11.2 million; although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act2013.
Entergy Gulf States Louisiana, L.L.C.
Management’s Financial Discussion and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Arkansas’ pension contributions in the future.Analysis
Total postretirement health care and life insurance benefit costs for Entergy ArkansasGulf States Louisiana in 20092012 were $21.9$21.3 million, including $4.9$3.7 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy ArkansasGulf States Louisiana expects 20102013 postretirement health care and life insurance benefit costs to approximate $18.9$20.8 million, including $5.3$3.9 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy ArkansasGulf States Louisiana contributed $7.6 million to its other postretirement plans in 2012 and expects to contribute approximately $21.6$8.4 million to other postretirement plans in 2010.2013.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion.Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Entergy Arkansas, Inc.
Little Rock, Arkansas
We have audited the accompanying balance sheets of Entergy Arkansas, Inc. (the “Company”) as of December 31, 2009 and 2008, and the related statements of income, retained earnings, and cash flows (pages 273 through 278 and applicable items in pages 63 through 193) for each of the three years in the period ended December 31, 2009. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Arkansas, Inc. as of December 31, 2009 and 2008, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009, based on the criteria established in Internal Control – Integrated FrameworkContents issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 2010 expressed an unqualified opinion on the Company’s internal control over financial reporting.
DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 2010
| ENTERGY ARKANSAS, INC. | |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 2,211,263 | | | $ | 2,328,349 | | | $ | 2,032,965 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 298,219 | | | | 283,547 | | | | 132,830 | |
| Purchased power | | | 795,526 | | | | 953,663 | | | | 818,549 | |
| Nuclear refueling outage expenses | | | 42,148 | | | | 29,611 | | | | 28,511 | |
| Other operation and maintenance | | | 475,222 | | | | 524,940 | | | | 458,042 | |
| Decommissioning | | | 34,575 | | | | 35,083 | | | | 32,816 | |
| Taxes other than income taxes | | | 80,829 | | | | 85,590 | | | | 78,449 | |
| Depreciation and amortization | | | 252,742 | | | | 237,168 | | | | 228,354 | |
| Other regulatory charges (credits) - net | | | 15,161 | | | | (26,747 | ) | | | (29,001 | ) |
| TOTAL | | | 1,994,422 | | | | 2,122,855 | | | | 1,748,550 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 216,841 | | | | 205,494 | | | | 284,415 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 5,219 | | | | 6,259 | | | | 11,143 | |
| Interest and dividend income | | | 19,321 | | | | 21,174 | | | | 19,116 | |
| Miscellaneous - net | | | (3,569 | ) | | | (4,731 | ) | | | (3,263 | ) |
| TOTAL | | | 20,971 | | | | 22,702 | | | | 26,996 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 85,484 | | | | 79,945 | | | | 77,348 | |
| Other interest - net | | | 6,856 | | | | 7,787 | | | | 14,392 | |
| Allowance for borrowed funds used during construction | | | (3,159 | ) | | | (3,311 | ) | | | (5,078 | ) |
| TOTAL | | | 89,181 | | | | 84,421 | | | | 86,662 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 148,631 | | | | 143,775 | | | | 224,749 | |
| | | | | | | | | | | | | |
| Income taxes | | | 81,756 | | | | 96,623 | | | | 85,638 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 66,875 | | | | 47,152 | | | | 139,111 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 6,873 | | | | 6,873 | | | | 6,873 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 60,002 | | | $ | 40,279 | | | $ | 132,238 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
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| ENTERGY ARKANSAS, INC. | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 66,875 | | | $ | 47,152 | | | $ | 139,111 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Reserve for regulatory adjustments | | | (169 | ) | | | (751 | ) | | | (16,248 | ) |
| Other regulatory charges (credits) - net | | | 15,161 | | | | (26,747 | ) | | | (29,001 | ) |
| Depreciation, amortization, and decommissioning | | | 287,317 | | | | 272,251 | | | | 261,170 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 66,777 | | | | 186,283 | | | | 58,796 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 3,477 | | | | 67,197 | | | | (24,958 | ) |
| Fuel inventory | | | 163 | | | | 5,282 | | | | 2,468 | |
| Accounts payable | | | (338,993 | ) | | | 67,148 | | | | 327,578 | |
| Taxes accrued | | | - | | | | - | | | | (37,161 | ) |
| Interest accrued | | | (1,103 | ) | | | 7,760 | | | | (2,132 | ) |
| Deferred fuel costs | | | (3,741 | ) | | | (4,298 | ) | | | (112,606 | ) |
| Other working capital accounts | | | 330,263 | | | | (177,725 | ) | | | (274,898 | ) |
| Provision for estimated losses and reserves | | | (2,708 | ) | | | 1,511 | | | | (125 | ) |
| Changes in other regulatory assets | | | (70,412 | ) | | | (219,091 | ) | | | 15,626 | |
| Changes in pension and other postretirement liabilities | | | 6,501 | | | | 181,539 | | | | 1,234 | |
| Other | | | 24,784 | | | | 52,740 | | | | 57,264 | |
| Net cash flow provided by operating activities | | | 384,192 | | | | 460,251 | | | | 366,118 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (338,752 | ) | | | (373,973 | ) | | | (304,901 | ) |
| Allowance for equity funds used during construction | | | 5,219 | | | | 6,259 | | | | 11,143 | |
| Nuclear fuel purchases | | | (118,379 | ) | | | (105,279 | ) | | | (40,353 | ) |
| Proceeds from sale/leaseback of nuclear fuel | | | 118,590 | | | | 105,062 | | | | 42,444 | |
| Payment for purchase of plant | | | - | | | | (210,029 | ) | | | - | |
| Proceeds from sale of plant | | | 74,818 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 154,644 | | | | 162,126 | | | | 96,034 | |
| Investment in nuclear decommissioning trust funds | | | (164,879 | ) | | | (176,676 | ) | | | (108,814 | ) |
| Change in money pool receivable - net | | | (12,868 | ) | | | (15,991 | ) | | | 14,298 | |
| Other | | | 95 | | | | - | | | | 19 | |
| Net cash flow used in investing activities | | | (281,512 | ) | | | (608,501 | ) | | | (290,130 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | - | | | | 297,261 | | | | - | |
| Change in money pool payable - net | | | - | | | | (77,882 | ) | | | 77,882 | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (48,300 | ) | | | (24,900 | ) | | | (181,600 | ) |
| Preferred stock | | | (6,873 | ) | | | (6,873 | ) | | | (6,873 | ) |
| Other | | | (842 | ) | | | - | | | | - | |
| Net cash flow provided by (used in) financing activities | | | (56,015 | ) | | | 187,606 | | | | (110,591 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 46,665 | | | | 39,356 | | | | (34,603 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 39,568 | | | | 212 | | | | 34,815 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 86,233 | | | $ | 39,568 | | | $ | 212 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid/(received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 88,397 | | | $ | 71,645 | | | $ | 80,762 | |
| Income taxes | | $ | 1,434 | | | $ | (57,902 | ) | | $ | 21,862 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents | | | | | | |
| Cash | | $ | 3,336 | | | $ | 3,292 | |
| Temporary cash investments | | | 82,897 | | | | 36,276 | |
| Total cash and cash investments | | | 86,233 | | | | 39,568 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 93,754 | | | | 113,135 | |
| Allowance for doubtful accounts | | | (21,853 | ) | | | (19,882 | ) |
| Associated companies | | | 91,650 | | | | 56,534 | |
| Other | | | 55,381 | | | | 64,762 | |
| Accrued unbilled revenues | | | 76,126 | | | | 71,118 | |
| Total accounts receivable | | | 295,058 | | | | 285,667 | |
| Deferred fuel costs | | | 122,802 | | | | 119,061 | |
| Fuel inventory - at average cost | | | 15,060 | | | | 15,223 | |
| Materials and supplies - at average cost | | | 132,182 | | | | 121,769 | |
| Deferred nuclear refueling outage costs | | | 34,492 | | | | 42,932 | |
| System agreement cost equalization | | | 70,000 | | | | 394,000 | |
| Prepayments and other | | | 32,668 | | | | 36,530 | |
| TOTAL | | | 788,495 | | | | 1,054,750 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 11,201 | | | | 11,200 | |
| Decommissioning trust funds | | | 440,220 | | | | 390,529 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 1,435 | | | | 1,439 | |
| Other | | | 2,976 | | | | 5,391 | |
| TOTAL | | | 455,832 | | | | 408,559 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 7,602,975 | | | | 7,305,165 | |
| Property under capital lease | | | 1,364 | | | | 1,417 | |
| Construction work in progress | | | 114,998 | | | | 142,391 | |
| Nuclear fuel under capital lease | | | 173,076 | | | | 125,072 | |
| Nuclear fuel | | | 11,543 | | | | 12,115 | |
| TOTAL UTILITY PLANT | | | 7,903,956 | | | | 7,586,160 | |
| Less - accumulated depreciation and amortization | | | 3,534,056 | | | | 3,272,280 | |
| UTILITY PLANT - NET | | | 4,369,900 | | | | 4,313,880 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 51,340 | | | | 58,455 | |
| Other regulatory assets | | | 746,955 | | | | 688,964 | |
| Other | | | 23,118 | | | | 43,605 | |
| TOTAL | | | 821,413 | | | | 791,024 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 6,435,640 | | | $ | 6,568,213 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY ARKANSAS, INC. |
| BALANCE SHEETS |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | | | | | | | |
| | | December 31, | |
| | | | 2009 | | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | | $ | 100,000 | | | $ | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 107,584 | | | | 433,460 | |
| Other | | | 111,523 | | | | 142,974 | |
| Customer deposits | | | 67,480 | | | | 60,558 | |
| Accumulated deferred income taxes | | | 74,794 | | | | 198,902 | |
| Interest accrued | | | 24,104 | | | | 25,207 | |
| Obligations under capital leases | | | 72,838 | | | | 60,276 | |
| Other | | | 14,742 | | | | 17,290 | |
| TOTAL | | | 573,065 | | | | 938,667 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 1,493,580 | | | | 1,307,596 | |
| Accumulated deferred investment tax credits | | | 47,909 | | | | 51,881 | |
| Obligations under capital leases | | | 101,601 | | | | 66,214 | |
| Other regulatory liabilities | | | 101,370 | | | | 27,141 | |
| Decommissioning | | | 566,374 | | | | 540,709 | |
| Accumulated provisions | | | 13,217 | | | | 15,925 | |
| Pension and other postretirement liabilities | | | 448,421 | | | | 441,920 | |
| Long-term debt | | | 1,518,569 | | | | 1,618,171 | |
| Other | | | 43,623 | | | | 43,780 | |
| TOTAL | | | 4,334,664 | | | | 4,113,337 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 116,350 | | | | 116,350 | |
| | | | | | | | | |
| SHAREHOLDERS' EQUITY | | | | | | | | |
| Common stock, $0.01 par value, authorized 325,000,000 | | | | | | | | |
| shares; issued and outstanding 46,980,196 shares in 2009 | | | | | | | | |
| and 2008 | | | 470 | | | | 470 | |
| Paid-in capital | | | 588,444 | | | | 588,444 | |
| Retained earnings | | | 822,647 | | | | 810,945 | |
| TOTAL | | | 1,411,561 | | | | 1,399,859 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 6,435,640 | | | $ | 6,568,213 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | |
| ENTERGY ARKANSAS, INC. | |
| STATEMENTS OF RETAINED EARNINGS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Retained Earnings, January 1 | | $ | 810,945 | | | $ | 795,566 | | | $ | 844,928 | |
| | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | |
| Net income | | | 66,875 | | | | 47,152 | | | | 139,111 | |
| | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | |
| Dividends declared on common stock | | | 48,300 | | | | 24,900 | | | | 181,600 | |
| Preferred dividend requirements and other | | | 6,873 | | | | 6,873 | | | | 6,873 | |
| Total | | | 55,173 | | | | 31,773 | | | | 188,473 | |
| | | | | | | | | | | | | |
| Retained Earnings, December 31 | | $ | 822,647 | | | $ | 810,945 | | | $ | 795,566 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 2,211,263 | | | $ | 2,328,349 | | | $ | 2,032,965 | | | $ | 2,092,683 | | | $ | 1,789,055 | |
| Net Income | | $ | 66,875 | | | $ | 47,152 | | | $ | 139,111 | | | $ | 173,154 | | | $ | 174,635 | |
| Total assets | | $ | 6,435,640 | | | $ | 6,568,213 | | | $ | 5,999,806 | | | $ | 5,541,036 | | | $ | 5,368,010 | |
| Long-term obligations (1) | | $ | 1,620,170 | | | $ | 1,684,385 | | | $ | 1,391,808 | | | $ | 1,380,046 | | | $ | 1,353,462 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 769 | | | $ | 756 | | | $ | 690 | | | $ | 706 | | | $ | 620 | |
| Commercial | | | 475 | | | | 463 | | | | 409 | | | | 418 | | | | 348 | |
| Industrial | | | 433 | | | | 461 | | | | 407 | | | | 436 | | | | 362 | |
| Governmental | | | 21 | | | | 21 | | | | 19 | | | | 19 | | | | 18 | |
| Total retail | | | 1,698 | | | | 1,701 | | | | 1,525 | | | | 1,579 | | | | 1,348 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 350 | | | | 416 | | | | 302 | | | | 328 | | | | 192 | |
| Non-associated companies | | | 102 | | | | 156 | | | | 156 | | | | 145 | | | | 211 | |
| Other | | | 61 | | | | 55 | | | | 50 | | | | 41 | | | | 38 | |
| Total | | $ | 2,211 | | | $ | 2,328 | | | $ | 2,033 | | | $ | 2,093 | | | $ | 1,789 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 7,464 | | | | 7,678 | | | | 7,725 | | | | 7,655 | | | | 7,653 | |
| Commercial | | | 5,817 | | | | 5,875 | | | | 5,945 | | | | 5,816 | | | | 5,730 | |
| Industrial | | | 6,376 | | | | 7,211 | | | | 7,424 | | | | 7,587 | | | | 7,334 | |
| Governmental | | | 269 | | | | 274 | | | | 277 | | | | 273 | | | | 288 | |
| Total retail | | | 19,926 | | | | 21,038 | | | | 21,371 | | | | 21,331 | | | | 21,005 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 9,980 | | | | 7,890 | | | | 7,185 | | | | 7,679 | | | | 4,555 | |
| Non-associated companies | | | 1,631 | | | | 2,159 | | | | 2,651 | | | | 2,929 | | | | 4,103 | |
| Total | | | 31,537 | | | | 31,087 | | | | 31,207 | | | | 31,939 | | | | 29,663 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
ENTERGY GULF STATES LOUISIANA, L.L.C.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating under the sole retail jurisdiction of the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Management believes that the jurisdictional separation will better align Entergy Gulf States, Inc.'s Louisiana and Texas operations to serve customers in those states and to operate consistent with state-specific regulatory requirements as the utility regulatory environments in those jurisdictions evolve. The jurisdictional separation provides for regulation of each separated company by a single retail regulator, which should reduce regulatory complexity.
Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares of Entergy Gulf States, Inc.'s 70% ownership interest in Nelson 6 and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Gulf States Louisiana remains primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, of which $168 million remains outstanding at December 31, 2009. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation. Entergy Texas' debt assumption does not discharge Entergy Gulf States Louisiana's liability for the long-term debt. To secure its debt assumption obligations, Entergy Texas granted to Entergy Gulf States Louisiana a first lien on Entergy Texas' assets that were previously subject to the Entergy Gulf States, Inc. mortgage. Entergy Texas has until December 31, 2010 to repay the assumed debt. In addition, Entergy Texas, as the owner of Entergy Gulf States Reconstruction Funding I, LLC ("EGSRF I"), reports the $329.5 million of senior secured transition bonds ("securitization bonds") issued by EGSRF I as long-term debt on its consolidated balance sheet. The securitization bonds are non-recourse to Entergy Texas.
Entergy Texas will purchase from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement (PPA) a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend's nuclear and environmental liabilities that is identical to the share of the plant's output purchased by Entergy Texas under the PPA. Entergy Gulf States Louisiana will purchase a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas will purchase a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The PPAs associated with the gas-fired generating plants will terminate when retail open access commences in Entergy Texas' jurisdiction or when the unit(s) is no longer dispatched by the Entergy System. If Entergy Texas implements retail open access, it will terminate its participation in the System Agreement, except for the portion of the System Agreement related to transmission equalization. The dispatch and operation of the generating plants will not change as a result of the jurisdictional separation.
As the successor to Entergy Gulf States, Inc. for financial reporting purposes, Entergy Gulf States Louisiana's income statement and cash flow statement for the year ended December 31, 2007 include the operations of Entergy Texas.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Results of Operations
Effect of Jurisdictional Separation on 2008 Results of Operations
Following are income statement variances for Entergy Gulf States Louisiana comparing the year ended December 31, 2008 to the year ended December 31, 2007 showing how much the line item increased or (decreased) in comparison to the prior period:
| | | Year ended December 31, 2007 | | Variance caused directly by the jurisdictional separation | | Variance caused by other factors | | Year ended December 31, 2008 |
| | | (In Thousands) |
| | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | | | | | | | | |
| Other operation and maintenance expenses | | 548,999 | | (179,119) | | (32,086) | | 337,794 |
| Taxes other than income taxes | | 132,489 | | (50,617) | | (4,434) | | 77,438 |
| Depreciation and amortization | | 208,648 | | (68,172) | | (3,870) | | 136,606 |
| Other expenses | | 23,940 | | (173) | | 14,471 | | 38,238 |
| Other income | | 88,815 | | 26,020 | | (29,829) | | 85,006 |
| Interest charges | | 155,881 | | (23,012) | | (6,109) | | 126,760 |
| Income taxes | | 123,701 | | (36,249) | | (30,255) | | 57,197 |
| | | | | | | | | |
| Net Income (Loss) | | $192,779 | | ($58,921) | | $10,909 | | $144,767 |
Net Income
2009 Compared to 2008
Net income increased by $8.3 million primarily due to higher net revenue, lower interest and other charges, and lower taxes other than income taxes, partially offset by a higher effective income tax rate and lower other income.
2008 Compared to 2007
Net income decreased $48 million primarily due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007, in addition to lower other income and lower net revenue other than the effects directly caused by the jurisdictional separation, partially offset by lower other operation and maintenance expenses and a lower effective income tax rate. For the year ended December 31, 2007, Entergy Texas reported net income of $58.9 million.
Net Revenue
2009 Compared to 2008
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory credits. Following is an analysis of the change in net revenue comparing 2009 to 2008.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $833.8 |
Fuel recovery | | 22.1 |
Volume/weather | | 18.2 |
Retail electric price | | (13.3) |
Other | | 0.5 |
2009 net revenue | | $861.3 |
The fuel recovery variance resulted primarily from an adjustment to deferred fuel costs in the fourth quarter 2009 relating to unrecovered nuclear fuel costs incurred since January 2008 that will now be recovered after a revision to the fuel adjustment clause methodology.
The volume/weather variance is primarily due to an increase in unbilled sales volume, including the effects of Hurricane Gustav and Hurricane Ike which decreased sales volume in 2008, and the effect of more favorable weather.
The retail electric price variance is primarily due to:
· | a formula rate plan provision of $3.7 million recorded in the third quarter of 2009 for refunds made to customers in November 2009 in accordance with a settlement approved by the LPSC. See Note 2 to the financial statements for further discussion of the settlement; |
· | a credit passed on to customers as a result of the Act 55 storm cost financing; and |
· | a net decrease in the formula rate plan effective September 2008 to remove interim storm recovery upon the Act 55 financing of storm costs as well as the storm damage accrual. A portion of the decrease is offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the formula rate plan. |
The decrease was partially offset by a formula rate plan increase effective September 2008 and November 2009. Refer to "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - State and Local Rate Regulation - -Retail Rates - Electric" and Note 2 to the financial statements for a discussion of the formula rate plan.
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues decreased primarily due to:
· | a decrease of $638.2 million in electric fuel cost recovery revenues due to lower fuel rates; |
· | a decrease of $245 million in gross wholesale revenue due to a decrease in the average price of energy available for resale sales; and |
· | a decrease of $33.5 million in gross gas revenue primarily due to lower fuel rates. |
The decrease was partially offset by formula rate plan increases effective November 2009 as discussed above.
Fuel and purchased power expenses decreased primarily due to a decrease in the average market prices of natural gas and purchased power and a decrease in deferred fuel expense due to decreased recovery from customers of fuel costs in addition to a credit recorded in the fourth quarter 2009 as a result of a revision to the fuel adjustment clause methodology as explained above.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
2008 Compared to 2007
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 2008 to 2007.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $1,297.6 |
Jurisdictional separation | | (442.3) |
Other | | (21.5) |
2008 net revenue | | $833.8 |
Net revenue decreased primarily due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007.
The Other variance is primarily caused by various operational effects of the jurisdictional separation on revenues and fuel and purchased power expenses.
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)
The change in gross operating revenues, fuel and purchased power expenses, and other regulatory charges was primarily caused by the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007.
Other Income Statement Variances
2009 Compared to 2008
Other operation and maintenance expenses decreased primarily due to a decrease of $7.7 million in storm damage reserves in 2009 as a result of the completion of the Act 55 storm cost financing and a decrease of $5.5 million in payroll-related costs. The decrease was partially offset by an increase of $7.8 million in nuclear expenses due to higher nuclear labor and contract costs.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes as a result of lower residential and commercial revenue.
Other income decreased primarily due to:
· | a decrease of $15.6 million in interest and dividend income related to the debt assumption agreement with Entergy Texas. Entergy Gulf States Louisiana remains primarily liable on this debt, of which $168 million remained outstanding as of December 31, 2009 and $770 million remained outstanding as of December 31, 2008; |
· | the decrease of $4.7 million in carrying charges on Hurricane Katrina and Hurricane Rita storm restoration costs as a result of the Act 55 storm cost financing; and |
· | a decrease of $3.5 million in interest earned on money pool investments. |
The decrease is partially offset by additional distributions of $8.7 million earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received from the Act 55 storm costs financings and $5.5 million in carrying charges on Hurricane Gustav and Hurricane Ike storm restoration costs. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
Interest expense decreased primarily due to a decrease of $421 million in long-term debt outstanding. See Note 5 to the financial statements for a description of the decrease in long-term debt.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
2008 Compared to 2007
Other operation and maintenance expenses decreased primarily due to:
· | a decrease of $179.1 million due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007; |
· | a decrease of $16.3 million in payroll, payroll-related, and benefit costs; |
· | a decrease of $9.7 million in nuclear labor and contract costs due to a non-refueling plant outage in March 2007; and |
· | a decrease of $10.1 million in plant maintenance costs. |
The decrease was partially offset by an increase of $8.8 million in transmission spending due to higher transmission equalization expenses.
Taxes other than income taxes decreased primarily due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007.
Nuclear refueling outage expenses increased due to the amortization of higher expenses associated with the planned maintenance and refueling outage at River Bend in the first quarter 2008 as well as the delay of this outage from late 2007 to early 2008 resulting in a shorter amortization period for these costs.
Depreciation and amortization decreased primarily due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007.
Other income includes $60 million in interest and dividend income in 2008 related to the debt assumption agreement between Entergy Gulf States Louisiana and Entergy Texas and the $1.079 billion of debt assumed by Entergy Texas as of December 31, 2007. Entergy Gulf States Louisiana remains primarily liable on this debt, of which $770 million remained outstanding at December 31, 2008. The increase in interest income is partially offset by $34 million of other income reported by Entergy Texas for the year ended December 31, 2007. The income from the debt assumption agreement offsets the interest expense on the portion of long-term debt assumed by Entergy Texas. The remaining variance is primarily due to the cessation of carrying charges on storm restoration costs as a result of the securitization and a decrease in interest earned on money pool investments, partially offset by dividends of $10.3 million earned on preferred stock purchased from Entergy Holdings Company with the proceeds received from the Act 55 Storm Cost Financings. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
Interest and other charges decreased primarily due to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007 and due to a decrease in long-term debt outstanding.
Income Taxes
The effective income tax rates were 36.8%, 28.3%, and 39.1% for 2009, 2008, and 2007, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008, and 2007 were as follows:
| | | | 2009 | | 2008 | | 2007 |
| | | | (In Thousands) |
| | | | | | | | |
| Cash and cash equivalents at beginning of period | | $49,303 | | $108,036 | | $180,381 |
| | | | | | | | |
| Cash flow provided by (used in): | | | | | | |
| | Operating activities | | 234,930 | | 562,897 | | 560,740 |
| | Investing activities | | (286,486) | | (519,364) | | (801,499) |
| | Financing activities | | 146,713 | | (102,266) | | 168,414 |
| | Net increase (decrease) in cash and cash equivalents | | 95,157 | | (58,733) | | (72,345) |
| | | | | | | | |
| Cash and cash equivalents at end of period | | $144,460 | | $49,303 | | $108,036 |
Operating Activities
Net cash flow provided by operating activities decreased $328 million in 2009 compared to 2008 primarily due to storm cost proceeds of $274.7 million received from the Louisiana Utilities Restoration Corporation (LURC) as a result of the Act 55 storm cost financing in 2008, decreased recovery of deferred fuel costs, and income tax payments of $60.6 million in 2009 compared to income tax refunds of $1.8 million in 2008, partially offset by a decrease of $28.2 million in pension contributions and fluctuation in the timing of accounts receivable and payable activity.
Net cash flow provided by operating activities increased $2.2 million in 2008 compared to 2007 primarily due to storm cost proceeds of $274.7 million received from the LURC as a result of the Act 55 storm cost financing, almost entirely offset by the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 31, 2007, increased recovery of fuel costs, and an increase of $17.9 million in pension contributions. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
Investing Activities
Net cash flow used in investing activities decreased $232.9 million in 2009 compared to 2008 primarily due to:
· | the investment of $189.4 million in affiliate securities in 2008 as a result of the Act 55 storm cost financing. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; |
· | higher construction expenditures in 2008 due to Hurricane Gustav; |
· | the purchase of the Calcasieu Generating Facility for $56 million in March 2008; and |
· | timing differences between nuclear fuel purchases and fuel trust reimbursements. |
The decrease was partially offset by money pool activity and the purchase of one-third of the Ouachita Power Plant for $75 million in November 2009 from Entergy Arkansas. See "Ouachita Power Plant" below for a discussion of the purchase of the Ouachita Power Plant. Increases in Entergy Gulf States Louisiana's receivable from the money pool are a use of cash flow, and Entergy Gulf States Louisiana's receivable from the money pool increased by $38.5 million for the year ended December 31, 2009 compared to decreasing by $43.9 million for the year ended December 31, 2008. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries' need for external short-term borrowings.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Net cash used in investing activities decreased $282.1 million in 2008 compared to 2007 primarily due to the cash allocated to Entergy Texas in the jurisdictional separation transaction in 2007 and due to the effect of the jurisdictional separation on money pool activity. The decrease was partially offset by the investment of $189.4 million in affiliate securities as a result of the Act 55 storm costs financings and the purchase of the Calcasieu Generating Facility for $56 million. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing. In March 2008, Entergy Gulf States Louisiana purchased Calcasieu, a 322 MW, simple-cycle, gas-fired power plant, from a subsidiary of Dynegy Inc. The facility is located near the city of Sulphur in southwestern Louisiana. Entergy Gulf States Louisiana received the plant, materials and supplies, SO2 emission allowances, and related real estate in the transaction. The FERC and the LPSC approved the acquisition.
Decreases in Entergy Gulf States Louisiana's receivable from the money pool are a source of cash flow, and Entergy Gulf States Louisiana's receivable from the money pool decreased by $43.9 million for the year ended December 31, 2008 compared to increasing by $134.6 million for the year ended December 31, 2007.
Financing Activities
Financing activities provided cash of $146.7 million in 2009 compared to using cash of $102.3 million in 2008 primarily due to the issuance of $300 million of 5.59% Series first mortgage bonds in October 2009 and a decrease of $73.5 million in common equity distributions, partially offset by the retirement of $119 million of long term debt in 2009.
Financing activities used cash of $102.3 million in 2008 compared to providing cash of $168.4 million in 2007 primarily due to the issuance of $329.5 million of securitization bonds in June 2007 by a subsidiary of Entergy Texas, partially offset by the redemption of all outstanding shares of Entergy Gulf States, Inc.'s preferred stock in December 2007.
Capital Structure
Entergy Gulf States Louisiana's capitalization is balanced between equity and debt, as shown in the following table. The calculation below does not reduce the debt by the debt assumed by Entergy Texas ($168 million as of December 31, 2009, and $770 million as of December 31, 2008) because Entergy Gulf States Louisiana remains primarily liable on the debt. The reduction in the debt to capital ratio in 2009 is primarily due to the repayment in 2009 of $602 million of assumed debt by Entergy Texas.
| | | December 31, 2009 | | December 31, 2008 |
| | | | | |
| Net debt to net capital | | 53.0% | | 61.6% |
| Effect of subtracting cash from debt | | 2.1% | | 0.6% |
| Debt to capital | | 55.1% | | 62.2% |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable, capital lease obligations, preferred membership interests with sinking fund, and long-term debt, including the currently maturing portion. Capital consists of debt and members' equity. Net capital consists of capital less cash and cash equivalents. Entergy Gulf States Louisiana uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Gulf States Louisiana's financial condition.
Uses of Capital
Entergy Gulf States Louisiana requires capital resources for:
· | construction and other capital investments; |
· | debt and preferred equity maturities; |
· | working capital purposes, including the financing of fuel and purchased power costs; and |
· | distribution and interest payments. |
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Following are the amounts of Entergy Gulf States Louisiana's planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:
| | 2010 | | 2011-2012 | | 2013-2014 | | after 2014 | | Total | |
| | (In Millions) |
| Planned construction and | | | | | | | | | | |
| capital investment (1) | $255 | | $488 | | N/A | | N/A | | $743 | |
| Long-term debt (2) | $105 | | $406 | | $194 | | $2,020 | | $2,725 | |
| Operating leases | $13 | | $22 | | $27 | | $61 | | $123 | |
| Purchase obligations (3) | $156 | | $221 | | $73 | | $78 | | $528 | |
| Nuclear fuel lease obligations (4) | $30 | | $126 | | N/A | | N/A | | $156 | |
(1) | Includes approximately $128 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. |
(2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
(3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Gulf States Louisiana, it primarily includes unconditional fuel and purchased power obligations. |
(4) | It is expected that additional financing under the leases will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, Entergy Gulf States Louisiana must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. |
In addition to the contractual obligations given above, Entergy Gulf States Louisiana expects to contribute $21.9 million to its pension plans and $8.4 million to other postretirement plans in 2010; although the required pension contributions will not be known with more certainty until the January 1, 2010 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Gulf States Louisiana’s pension contributions in the future.
Also, in addition to the contractual obligations, Entergy Gulf States Louisiana has $245.8 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
The planned capital investment estimate for Entergy Gulf States Louisiana reflects capital required to support existing business and customer growth. Entergy's Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, and the ability to access capital. Management provides more information on long-term debt and preferred membership interest maturities in Notes 5 and 6 to the financial statements.
As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Gulf States Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Gulf States Louisiana's long-term debt indentures contain restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Ouachita Power Plant
In August 2008, the LPSC issued an order approving an uncontested settlement between Entergy Gulf States Louisiana and the LPSC Staff authorizing Entergy Gulf States Louisiana's purchase, under a life-of-unit agreement, of one-third of the capacity and energy from the 789 MW Ouachita power plant. The LPSC's approval was subject to certain conditions, including a study to determine the costs and benefits of Entergy Gulf States Louisiana exercising an option to purchase one-third of the plant (Unit 3) from Entergy Arkansas. In April 2009, Entergy Gulf States Louisiana made a filing with the LPSC seeking approval of Entergy Gulf States Louisiana exercising its option to convert its purchased power agreement into the ownership interest in Unit 3 and a one-third interest in the Ouachita common facilities. In September 2009 the LPSC, pursuant to an uncontested settlement, approved the acquisition and a cost recovery mechanism. Entergy Gulf States Louisiana purchased Unit 3 and a one-third interest in the Ouachita common facilities for $75 million in November 2009.
New Nuclear Development
Entergy Gulf States Louisiana and Entergy Louisiana provided public notice to the LPSC of their intention to make a filing pursuant to the LPSC's general order that governs the development of new nuclear generation in Louisiana. The project option being developed by the companies is for new nuclear generation at River Bend. Entergy Gulf States Louisiana and Entergy Louisiana, together with Entergy Mississippi, have been engaged in the development of options to construct new nuclear generation at the River Bend and Grand Gulf sites. Entergy Gulf States Louisiana and Entergy Louisiana are leading the development at River Bend, and Entergy Mississippi is leading the development at Grand Gulf. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and will recognize on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company's current participation level in the project. In response to the companies' previous notice, dated August 10, 2009, the LPSC opened a docket. A procedural schedule will be established after the companies file the certification application referred to in the notice.
Sources of Capital
Entergy Gulf States Louisiana's sources to meet its capital requirements include:
· | internally generated funds; |
· | debt or preferred membership interest issuances; and |
· | bank financing under new or existing facilities. |
Entergy Gulf States Louisiana may refinance or redeem debt and preferred equity/membership interests prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred equity/membership interest issuances by Entergy Gulf States Louisiana require prior regulatory approval. Preferred equity/membership interest and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures, and other agreements. Entergy Gulf States Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Gulf States Louisiana's receivables from the money pool were as follows as of December 31 for each of the following years:
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $50,131 | | $11,589 | | $55,509 | | $75,048 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Entergy Gulf States Louisiana has a credit facility in the amount of $100 million scheduled to expire in August 2012. No borrowings were outstanding under the credit facility as of December 31, 2009.
Entergy Gulf States Louisiana obtained short-term borrowing authorization from the FERC under which it may borrow through October 2011, up to the aggregate amount, at any one time outstanding, of $200 million. See Note 4 to the financial statements for further discussion of Entergy Gulf States Louisiana's short-term borrowing limits. Entergy Gulf States Louisiana has also obtained an order from the FERC authorizing long-term securities issuances through July 2011.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy Gulf States Louisiana's service territory. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. In October 2008, Entergy Gulf States Louisiana drew all of its $85 million funded storm reserve. On October 15, 2008, the LPSC approved Entergy Gulf States Louisiana's request to defer and accrue carrying cost on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm cost or final carrying cost rate.
Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana made a supplemental filing to, among other things, recommend recovery of the costs and replenishment of the storm reserves by Louisiana Act 55 (passed in 2007) financing. Entergy Gulf States Louisiana and Entergy Louisiana recovered their costs from Hurricane Katrina and Hurricane Rita primarily by Act 55 financing, as discussed below. On December 30, 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that, if approved, provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when Act 55 financing is accomplished. The parties to the proceeding have agreed to a procedural schedule that includes March/April 2010 hearing dates for both the recoverability and the method of recovery proceedings.
Hurricane Rita and Hurricane Katrina
In August and September 2005, Hurricanes Katrina and Rita hit Entergy Gulf States Inc.'s jurisdictions in Louisiana and Texas. The storms resulted in power outages; significant damage to electric distribution, transmission, and generation infrastructure; and the temporary loss of sales and customers due to mandatory evacuations. Entergy Gulf States Louisiana pursued a range of initiatives to recover storm restoration and business continuity costs and incremental losses. Initiatives included obtaining reimbursement of certain costs covered by insurance and pursuing recovery through existing or new rate mechanisms regulated by the FERC and local regulatory bodies, in combination with securitization.
Insurance Claims
Entergy has received a total of $317 million as of December 31, 2009 on its Hurricane Katrina and Hurricane Rita insurance claims, including the settlements of its Hurricane Katrina claims with each of its two excess insurers. Of the $317 million received, $21 million was allocated to Entergy Gulf States Louisiana. Entergy has substantially completed its insurance recoveries related to Hurricane Katrina and Hurricane Rita.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Storm Cost Financings
In March 2008, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings are expected to produce additional customer benefits as compared to Act 64 traditional securitization. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 3, 2008, the Louisiana State Bond Commission granted preliminary approval for the Act 55 financings. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financings, approved requests for the Act 55 financings. On April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staff filed with the LPSC an uncontested stipulated settlement that includes Entergy Gulf States Louisiana and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10 million and $30 million of customer benefits, respectively, through prospective annual rate reductions of $2 million and $6 million for five years. On April 16, 2008, the LPSC approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financings. In May 2008, the Louisiana State Bond Commission granted final approval of the Act 55 financings.
On August 26, 2008, the LPFA issued $278.4 million in bonds under the aforementioned Act 55. From the $274.7 million of bond proceeds loaned by the LPFA to the LURC, the LURC deposited $87 million in a restricted escrow account as a storm damage reserve for Entergy Gulf States Louisiana and transferred $187.7 million directly to Entergy Gulf States Louisiana. From the bond proceeds received by Entergy Gulf States Louisiana from the LURC, Entergy Gulf States Louisiana invested $189.4 million, including $1.7 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 1,893,918.39 Class A preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2008 and have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
Entergy Gulf States Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LPFA, and there is no recourse against Entergy Gulf States Louisiana in the event of a bond default.
State and Local Rate Regulation
The rates that Entergy Gulf States Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Gulf States Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC is primarily responsible for approval of the rates charged to customers.
Retail Rates - Electric
In March 2005, the LPSC approved a settlement proposal to resolve various dockets covering a range of issues for Entergy Gulf States Louisiana and Entergy Louisiana. The settlement included the establishment of a three-year formula rate plan for Entergy Gulf States Louisiana that, among other provisions, establishes a return on common equity mid-point of 10.65% for the initial three-year term of the plan and permits Entergy Gulf States Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed range of 9.9% to 11.4% are allocated 60% to customers and 40% to Entergy Gulf States Louisiana. Entergy Gulf States Louisiana made its initial formula rate plan filing in June 2005. The formula rate plan was subsequently extended one year. As discussed below the formula rate plan has been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, and 2010 test years.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
In October 2009 the LPSC approved a settlement that resolves Entergy Gulf States Louisiana's 2007 test year filing. The settlement provides for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Gulf States Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.65% return on equity for the 2008 test year. 10.65% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 75 basis points (9.90% - 11.40%). The rate reset, a $44.3 million increase that includes a $36.9 million cost of service adjustment, plus $7.4 million net for increased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset will be subject to refund pending review of the 2008 test year filing that was made on October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Gulf States Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlement Entergy Gulf States Louisiana refunded to its customers $3.7 million, which includes interest, in the November 2009 billing cycle. In January 2010, Entergy Gulf States Louisiana implemented an additional $23.9 million rate increase pursuant to a special rate implementation filing made in December 2009, primarily for incremental capacity costs approved by the LPSC. The discovery and comment period for the 2008 test year filing is currently open, and Entergy Gulf States Louisiana will implement any agreed changes by March 15, 2010. A procedural schedule to address any contested issues would be set after March 15, 2010.
In December 2009, Entergy Gulf States Louisiana filed an application seeking LPSC approval for a $9.7 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the LPSC-regulated 70% share of River Bend, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. Currently, Entergy Gulf States Louisiana's annual retail rates contain no amount for decommissioning funding.
In May 2008, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2007 test year. The filing reflected a 9.26% return on common equity, which was below the allowed earnings bandwidth, and indicated a $5.4 million revenue deficiency, offset by a $4.1 million decrease in required additional capacity costs. Entergy Gulf States Louisiana implemented a $20.7 million formula rate plan decrease, subject to refund, effective the first billing cycle in September 2008. The decrease included removal of interim storm cost recovery and a reduction in the storm damage accrual. Entergy Gulf States Louisiana then implemented a $16.0 million formula rate plan increase, subject to refund, effective the first billing cycle in October 2008 to collect previously deferred and ongoing costs associated with LPSC approved additional capacity, including the Ouachita power plant. In November 2008 Entergy Gulf States Louisiana filed to implement an additional increase of $9.3 million to recover the costs of a new purchased power agreement.
In May 2007, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2006 test year. The filing reflected a 10.0% return on common equity, which was within the allowed earnings bandwidth, and an anticipated formula rate plan decrease of $23 million annually attributable to adjustments outside of the formula rate plan sharing mechanism related to capacity costs and the anticipated securitization of storm costs related to Hurricane Katrina and Hurricane Rita and the securitization of a storm reserve. In September 2007, Entergy Gulf States Louisiana modified the formula rate plan filing to reflect a 10.07% return on common equity, which was still within the allowed bandwidth. The modified filing also reflected implementation of a $4.1 million rate increase, subject to refund, attributable to recovery of additional LPSC-approved incremental deferred and ongoing capacity costs. The rate decrease anticipated in the original filing did not occur because of the additional capacity costs approved by the LPSC, and because securitization of storm costs associated with Hurricane Katrina and Hurricane Rita and the establishment of a storm reserve had not yet occurred. In October 2007, Entergy Gulf States Louisiana implemented a $16.4 million formula rate plan decrease that was due to the reclassification of certain franchise fees from base rates to collection via a line item on customer bills pursuant to an LPSC order. In March 2008 the LPSC approved an uncontested stipulated settlement that left the current base rates in place and extended the formula rate plan for one year.
In May 2006, Entergy Gulf States Louisiana made its formula rate plan filing with the LPSC for the 2005 test year. Entergy Gulf States Louisiana modified the filing in August 2006 to reflect an 11.1% return on common equity which is within the allowed bandwidth. The modified filing includes a formula rate plan increase of $17.2 million annually that provides for 1) interim recovery of $10.5 million of storm costs from Hurricane Katrina and Hurricane Rita and 2) recovery of $6.7 million of LPSC-approved incremental deferred and ongoing
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
capacity costs. The increase was implemented with the first billing cycle of September 2006. In May 2007 the LPSC approved a settlement between Entergy Gulf States Louisiana and the LPSC staff, affirming the rates that were implemented in September 2006.
Retail Rates - Gas
In January 2010, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2009. The filing showed an earned return on common equity of 10.87%, which is within the earnings bandwidth of 10.5% plus or minus fifty basis points. The sixty day review and comment period for this filing remains open.
In January 2009, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ending September 30, 2008. The filing showed a revenue deficiency of $529 thousand based on a return on common equity mid-point of 10.5%. In April 2009, Entergy Gulf States Louisiana implemented a $255 thousand rate increase pursuant to an uncontested settlement with the LPSC staff.
In January 2008, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ending September 30, 2007. The filing showed a revenue deficiency of $3.7 million based on a return on common equity mid-point of 10.5%. Entergy Gulf States Louisiana implemented a $3.4 million rate increase in April 2008 pursuant to an uncontested agreement with the LPSC staff.
In January 2007, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ending September 30, 2006. The filing showed a revenue deficiency of $3.5 million based on a return on common equity mid-point of 10.5%. In March 2007, Entergy Gulf States Louisiana filed a set of rate and rider schedules that reflected all proposed LPSC staff adjustments and implemented a $2.4 million base rate increase effective with the first billing cycle of April 2007 pursuant to the rate stabilization plan.
Federal Regulation
System Agreement Proceedings
See "System Agreement Proceedings" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.
Transmission
See "Independent Coordinator of Transmission" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for further discussion.
Industrial and Commercial Customers
Entergy Gulf States Louisiana's large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Gulf States Louisiana's industrial customer base. Entergy Gulf States Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Gulf States Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Gulf States Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Gulf States Louisiana's marketing efforts in retaining industrial customers.
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
Nuclear Matters
Entergy Gulf States Louisiana owns and operates, through an affiliate, the River Bend nuclear power plant. Entergy Gulf States Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of River Bend, Entergy Gulf States Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
Environmental Risks
Entergy Gulf States Louisiana's facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Gulf States Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Gulf States Louisiana's financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Gulf States Louisiana's financial position or results of operations.
Nuclear Decommissioning Costs
See "Nuclear Decommissioning Costs" in the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Gulf States Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month's estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age while still working for Entergy. Entergy's reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions,
Entergy Gulf States Louisiana, L.L.C.
Management's Financial Discussion and Analysis
and accounting mechanisms. See the "Critical Accounting Estimates" section of Entergy Corporation and Subsidiaries Management's Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy's estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost to changes in certain actuarial assumptions (dollars in thousands):
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Discount rate | | (0.25%) | | $1,160 | | $12,054 |
| Rate of return on plan assets | | (0.25%) | | $884 | | - |
| Rate of increase in compensation | | 0.25% | | $542 | | $2,658 |
The following chart reflects the sensitivity of postretirement benefit cost to changes in certain actuarial assumptions (dollars in thousands):
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) |
| | | | | | | |
| Health care cost trend | | 0.25% | | $683 | | $3,814 |
| Discount rate | | (0.25%) | | $415 | | $4,074 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension income for Entergy Gulf States Louisiana in 2009 was $1.2 million. Entergy Gulf States Louisiana anticipates 2010 qualified pension cost to be $10 million. Entergy Gulf States Louisiana contributed $6 million to its pension plans in 2009 and estimates 2010 pension contributions to be approximately $21.9 million; although the required pension contributions will not be known with more certainty until the January 1, 2010 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Gulf States Louisiana’s pension contributions in the future.
Total postretirement health care and life insurance benefit costs for Entergy Gulf States Louisiana in 2009 were $14.7 million, including $3.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States Louisiana expects 2010 postretirement health care and life insurance benefit costs to approximate $16.6 million, including $3.4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Gulf States Louisiana expects to contribute approximately $8.4 million to its other postretirement plans in 2010.
New Accounting Pronouncements
See "New Accounting Pronouncements" section of Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for a discussion of new accounting pronouncements.
To the Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Baton Rouge, Louisiana
We have audited the accompanying balance sheets of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 20092012 and 2008,2011, and the related income statements, statements of income, members’ equity and comprehensive income, andstatements of cash flows, and statements of changes in equity (pages 296309 through 300314 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Gulf States Louisiana, L.L.C. as of December 31, 20092012 and 2008,2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, Entergy Gulf States, Inc. completed a jurisdictional separation on December 31, 2007. As part of the separation, Entergy Gulf States, Inc. contributed certain assets and liabilities to Entergy Texas, Inc. and Subsidiaries and reflected the distribution in the accompanying balance sheet and statement of members’ equity as of December 31, 2007.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,606,165 | | | $ | 2,069,548 | | | $ | 2,015,710 | |
| Natural gas | | | 48,729 | | | | 64,861 | | | | 81,311 | |
| TOTAL | | | 1,654,894 | | | | 2,134,409 | | | | 2,097,021 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 194,878 | | | | 437,301 | | | | 312,960 | |
| Purchased power | | | 562,247 | | | | 780,711 | | | | 851,694 | |
| Nuclear refueling outage expenses | | | 17,565 | | | | 18,227 | | | | 24,046 | |
| Other operation and maintenance | | | 361,415 | | | | 351,070 | | | | 361,329 | |
| Decommissioning | | | 15,024 | | | | 14,189 | | | | 13,400 | |
| Taxes other than income taxes | | | 76,295 | | | | 75,858 | | | | 77,519 | |
| Depreciation and amortization | | | 146,673 | | | | 143,387 | | | | 132,714 | |
| Other regulatory charges (credits) - net | | | 31,835 | | | | (17,045 | ) | | | (1,248 | ) |
| TOTAL | | | 1,405,932 | | | | 1,803,698 | | | | 1,772,414 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 248,962 | | | | 330,711 | | | | 324,607 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 8,694 | | | | 9,094 | | | | 5,513 | |
| Interest and investment income | | | 42,773 | | | | 40,945 | | | | 42,293 | |
| Miscellaneous - net | | | (8,928 | ) | | | (8,799 | ) | | | (8,016 | ) |
| TOTAL | | | 42,539 | | | | 41,240 | | | | 39,790 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 83,251 | | | | 84,356 | | | | 101,318 | |
| Allowance for borrowed funds used during construction | | | (3,343 | ) | | | (3,745 | ) | | | (3,537 | ) |
| TOTAL | | | 79,908 | | | | 80,611 | | | | 97,781 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 211,593 | | | | 291,340 | | | | 266,616 | |
| | | | | | | | | | | | | |
| Income taxes | | | 52,616 | | | | 89,736 | | | | 92,297 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 158,977 | | | | 201,604 | | | | 174,319 | |
| | | | | | | | | | | | | |
| Preferred distribution requirements and other | | | 825 | | | | 825 | | | | 827 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON EQUITY | | $ | 158,152 | | | $ | 200,779 | | | $ | 173,492 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 158,977 | | | $ | 201,604 | | | $ | 174,319 | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax expense (benefit) of $8,732, ($16,556), and ($340)) | | | 4,381 | | | | (29,306 | ) | | | 1,867 | |
| Other comprehensive income (loss) | | | 4,381 | | | | (29,306 | ) | | | 1,867 | |
| Comprehensive Income | | $ | 163,358 | | | $ | 172,298 | | | $ | 176,186 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 158,977 | | | $ | 201,604 | | | $ | 174,319 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 214,929 | | | | 207,753 | | | | 194,265 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 92,523 | | | | (4,845 | ) | | | 104,339 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 87,089 | | | | (82,221 | ) | | | (30,732 | ) |
| Fuel inventory | | | (3,718 | ) | | | 2,578 | | | | 3,471 | |
| Accounts payable | | | (1,725 | ) | | | (58,981 | ) | | | 80,874 | |
| Prepaid taxes and taxes accrued | | | (86,346 | ) | | | 148,313 | | | | (8,176 | ) |
| Interest accrued | | | (647 | ) | | | (1,177 | ) | | | 537 | |
| Deferred fuel costs | | | (96,230 | ) | | | 74,877 | | | | (20,050 | ) |
| Other working capital accounts | | | (5,548 | ) | | | (4,600 | ) | | | 13,068 | |
| Changes in provisions for estimated losses | | | (2,222 | ) | | | 1,353 | | | | 83,011 | |
| Changes in other regulatory assets | | | (73,082 | ) | | | (77,713 | ) | | | 141,216 | |
| Changes in pension and other postretirement liabilities | | | 83,440 | | | | 112,736 | | | | (14,041 | ) |
| Other | | | (21,232 | ) | | | (37,562 | ) | | | 4,029 | |
| Net cash flow provided by operating activities | | | 346,208 | | | | 482,115 | | | | 726,130 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (284,458 | ) | | | (219,307 | ) | | | (237,251 | ) |
| Allowance for equity funds used during construction | | | 8,694 | | | | 9,094 | | | | 5,513 | |
| Insurance proceeds | | | - | | | | - | | | | 2,243 | |
| Nuclear fuel purchases | | | (51,610 | ) | | | (87,901 | ) | | | (47,785 | ) |
| Proceeds from sale of nuclear fuel | | | 67,632 | | | | 9,647 | | | | - | |
| Investment in affiliates | | | - | | | | - | | | | (150,264 | ) |
| Payment to storm reserve escrow account | | | (99 | ) | | | (124 | ) | | | (90,073 | ) |
| Receipts from storm reserve escrow account | | | 3,364 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 131,042 | | | | 76,844 | | | | 100,825 | |
| Investment in nuclear decommissioning trust funds | | | (150,601 | ) | | | (94,922 | ) | | | (115,055 | ) |
| Change in money pool receivable - net | | | 23,596 | | | | 39,407 | | | | (12,872 | ) |
| Proceeds from the sale of investment | | | 51,000 | | | | - | | | | - | |
| Other | | | - | | | | - | | | | 3,136 | |
| Net cash flow used in investing activities | | | (201,440 | ) | | | (267,262 | ) | | | (541,583 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 74,251 | | | | - | | | | 306,234 | |
| Retirement of long-term debt | | | (70,840 | ) | | | (47,340 | ) | | | (344,841 | ) |
| Change in money pool payable - net | | | 7,074 | | | | - | | | | - | |
| Changes in credit borrowings - net | | | (29,400 | ) | | | 5,200 | | | | (10,100 | ) |
| Dividends/distributions paid: | | | | | | | | | | | | |
| Common equity | | | (114,200 | ) | | | (301,950 | ) | | | (124,300 | ) |
| Preferred membership interests | | | (825 | ) | | | (825 | ) | | | (827 | ) |
| Other | | | 13 | | | | (266 | ) | | | - | |
| Net cash flow used in financing activities | | | (133,927 | ) | | | (345,181 | ) | | | (173,834 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 10,841 | | | | (130,328 | ) | | | 10,713 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 24,845 | | | | 155,173 | | | | 144,460 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 35,686 | | | $ | 24,845 | | | $ | 155,173 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 80,848 | | | $ | 82,413 | | | $ | 97,803 | |
| Income taxes | | $ | 89,191 | | | $ | (56,289 | ) | | $ | (16,803 | ) |
| | | | | | | | | | | | | |
| Noncash financing activities: | | | | | | | | | | | | |
| Repayment by Entergy Texas of assumed long-term debt | | $ | - | | | $ | - | | | $ | 167,742 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. |
| INCOME STATEMENTS |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) |
| | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,776,610 | | | $ | 2,632,952 | | | $ | 3,448,008 | |
| Natural gas | | | 67,776 | | | | 100,413 | | | | 86,604 | |
| TOTAL | | | 1,844,386 | | | | 2,733,365 | | | | 3,534,612 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 251,393 | | | | 474,314 | | | | 867,081 | |
| Purchased power | | | 732,943 | | | | 1,425,936 | | | | 1,339,986 | |
| Nuclear refueling outage expenses | | | 21,787 | | | | 25,705 | | | | 12,212 | |
| Other operation and maintenance | | | 332,450 | | | | 337,794 | | | | 548,999 | |
| Decommissioning | | | 13,591 | | | | 12,533 | | | | 11,728 | |
| Taxes other than income taxes | | | 67,559 | | | | 77,438 | | | | 132,489 | |
| Depreciation and amortization | | | 135,489 | | | | 136,606 | | | | 208,648 | |
| Other regulatory charges (credits) - net | | | (1,261 | ) | | | (679 | ) | | | 29,923 | |
| TOTAL | | | 1,553,951 | | | | 2,489,647 | | | | 3,151,066 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 290,435 | | | | 243,718 | | | | 383,546 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 5,426 | | | | 7,417 | | | | 11,666 | |
| Interest and dividend income | | | 69,951 | | | | 83,105 | | | | 75,425 | |
| Miscellaneous - net | | | (8,764 | ) | | | (5,516 | ) | | | 1,724 | |
| TOTAL | | | 66,613 | | | | 85,006 | | | | 88,815 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 110,819 | | | | 123,439 | | | | 149,464 | |
| Other interest - net | | | 7,424 | | | | 7,758 | | | | 13,945 | |
| Allowance for borrowed funds used during construction | | | (3,427 | ) | | | (4,437 | ) | | | (7,528 | ) |
| TOTAL | | | 114,816 | | | | 126,760 | | | | 155,881 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 242,232 | | | | 201,964 | | | | 316,480 | |
| | | | | | | | | | | | | |
| Income taxes | | | 89,185 | | | | 57,197 | | | | 123,701 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 153,047 | | | | 144,767 | | | | 192,779 | |
| | | | | | | | | | | | | |
| Preferred distribution requirements and other | | | 825 | | | | 825 | | | | 3,968 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON EQUITY | | $ | 152,222 | | | $ | 143,942 | | | $ | 188,811 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 153,047 | | | $ | 144,767 | | | $ | 192,779 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Reserve for regulatory adjustments | | | - | | | | - | | | | 363 | |
| Other regulatory charges (credits) - net | | | (1,261 | ) | | | (679 | ) | | | 29,923 | |
| Depreciation, amortization, and decommissioning | | | 149,080 | | | | 149,139 | | | | 220,376 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 138,817 | | | | 47,846 | | | | 98,734 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 177,628 | | | | (8,661 | ) | | | (261,538 | ) |
| Fuel inventory | | | 4,453 | | | | (1,941 | ) | | | (18,377 | ) |
| Accounts payable | | | (131,603 | ) | | | (40,025 | ) | | | 38,685 | |
| Taxes accrued | | | (418 | ) | | | 418 | | | | (27,781 | ) |
| Interest accrued | | | (5,403 | ) | | | 714 | | | | 22,963 | |
| Deferred fuel costs | | | (49,625 | ) | | | 97,620 | | | | 35,363 | |
| Other working capital accounts | | | (116,816 | ) | | | (33,796 | ) | | | 197,802 | |
| Provision for estimated losses and reserves | | | 773 | | | | 2,009 | | | | (91,241 | ) |
| Changes in other regulatory assets | | | (44,612 | ) | | | 70,448 | | | | 116,317 | |
| Changes in pension and other postretirement liabilities | | | 46,083 | | | | 85,880 | | | | (39,324 | ) |
| Other | | | (85,213 | ) | | | 49,158 | | | | 45,696 | |
| Net cash flow provided by operating activities | | | 234,930 | | | | 562,897 | | | | 560,740 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (199,283 | ) | | | (303,468 | ) | | | (334,933 | ) |
| Allowance for equity funds used during construction | | | 5,426 | | | | 7,417 | | | | 11,666 | |
| Insurance proceeds | | | 2,180 | | | | - | | | | 6,580 | |
| Nuclear fuel purchases | | | (44,529 | ) | | | (55,001 | ) | | | (72,493 | ) |
| Proceeds from sale/leaseback of nuclear fuel | | | 72,843 | | | | 44,554 | | | | 54,362 | |
| Payment for purchase of plant | | | (74,818 | ) | | | (56,409 | ) | | | - | |
| Investment in affiliates | | | 160 | | | | (189,560 | ) | | | - | |
| Payments to storm reserve escrow account | | | - | | | | (85,306 | ) | | | - | |
| Receipts from storm reserve escrow account | | | - | | | | 85,254 | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 95,244 | | | | 65,125 | | | | 64,583 | |
| Investment in nuclear decommissioning trust funds | | | (105,167 | ) | | | (79,369 | ) | | | (78,720 | ) |
| Collections remitted to Texas transition charge account | | | - | | | | - | | | | (19,273 | ) |
| Change in money pool receivable - net | | | (38,542 | ) | | | 43,920 | | | | (134,636 | ) |
| Changes in other investments - net | | | - | | | | 3,934 | | | | (1,553 | ) |
| Cash allocated to Entergy Texas in jurisdictional separation | | | - | | | | - | | | | (297,082 | ) |
| Other | | | - | | | | (455 | ) | | | - | |
| Net cash flow used in investing activities | | | (286,486 | ) | | | (519,364 | ) | | | (801,499 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 297,199 | | | | 369,493 | | | | 323,464 | |
| Retirement of long-term debt | | | (118,961 | ) | | | (366,683 | ) | | | (5,530 | ) |
| Proceeds from issuance of preferred membership interests | | | - | | | | - | | | | 9,993 | |
| Redemption of preferred stock | | | - | | | | - | | | | (57,827 | ) |
| Dividends/distributions paid: | | | | | | | | | | | | |
| Common equity | | | (30,700 | ) | | | (104,200 | ) | | | (97,800 | ) |
| Preferred membership interests | | | (825 | ) | | | (859 | ) | | | (3,886 | ) |
| Other | | | - | | | | (17 | ) | | | - | |
| Net cash flow provided by (used in) financing activities | | | 146,713 | | | | (102,266 | ) | | | 168,414 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 95,157 | | | | (58,733 | ) | | | (72,345 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 49,303 | | | | 108,036 | | | | 180,381 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 144,460 | | | $ | 49,303 | | | $ | 108,036 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | |
| Cash paid/(received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 120,655 | | | $ | 127,152 | | | $ | 131,280 | |
| Income taxes | | $ | 60,594 | | | $ | (1,759 | ) | | $ | (5,938 | ) |
| | | | | | | | | | | | | |
| Noncash financing activities: | | | | | | | | | | | | |
| Repayment by Entergy Texas of assumed long-term debt | | $ | 602,229 | | | $ | 309,123 | | | $ | - | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 139 | | | $ | 22,671 | |
| Temporary cash investments | | | 144,321 | | | | 26,632 | |
| Total cash and cash equivalents | | | 144,460 | | | | 49,303 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 38,633 | | | | 69,264 | |
| Allowance for doubtful accounts | | | (1,235 | ) | | | (1,230 | ) |
| Associated companies | | | 102,807 | | | | 179,217 | |
| Other | | | 22,425 | | | | 60,618 | |
| Accrued unbilled revenues | | | 56,425 | | | | 50,272 | |
| Total accounts receivable | | | 219,055 | | | | 358,141 | |
| Accumulated deferred income taxes | | | - | | | | 50,039 | |
| Fuel inventory - at average cost | | | 29,298 | | | | 33,751 | |
| Materials and supplies - at average cost | | | 107,531 | | | | 104,579 | |
| Deferred nuclear refueling outage costs | | | 26,722 | | | | 17,135 | |
| Debt assumption by Entergy Texas | | | 167,742 | | | | 100,509 | |
| Prepayments and other | | | 42,146 | | | | 6,381 | |
| TOTAL | | | 736,954 | | | | 719,838 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliate preferred membership interests | | | 189,400 | | | | 189,560 | |
| Decommissioning trust funds | | | 349,527 | | | | 303,178 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 146,190 | | | | 120,829 | |
| Other | | | 11,342 | | | | 13,245 | |
| TOTAL | | | 696,459 | | | | 626,812 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 6,855,075 | | | | 6,402,668 | |
| Natural gas | | | 113,970 | | | | 106,125 | |
| Construction work in progress | | | 84,161 | | | | 201,544 | |
| Nuclear fuel under capital lease | | | 156,996 | | | | 140,689 | |
| Nuclear fuel | | | 6,005 | | | | 11,177 | |
| TOTAL UTILITY PLANT | | | 7,216,207 | | | | 6,862,203 | |
| Less - accumulated depreciation and amortization | | | 3,714,199 | | | | 3,560,458 | |
| UTILITY PLANT - NET | | | 3,502,008 | | | | 3,301,745 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 288,313 | | | | 316,421 | |
| Other regulatory assets | | | 299,793 | | | | 287,912 | |
| Deferred fuel costs | | | 100,124 | | | | 100,124 | |
| Long-term receivables | | | 967 | | | | 21,558 | |
| Debt assumption by Entergy Texas | | | - | | | | 669,462 | |
| Other | | | 11,564 | | | | 13,089 | |
| TOTAL | | | 700,761 | | | | 1,408,566 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 5,636,182 | | | $ | 6,056,961 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 35,085 | | | $ | 217 | |
| Temporary cash investments | | | 601 | | | | 24,628 | |
| Total cash and cash equivalents | | | 35,686 | | | | 24,845 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 53,480 | | | | 61,648 | |
| Allowance for doubtful accounts | | | (711 | ) | | | (843 | ) |
| Associated companies | | | 71,697 | | | | 171,431 | |
| Other | | | 18,736 | | | | 22,082 | |
| Accrued unbilled revenues | | | 51,586 | | | | 51,155 | |
| Total accounts receivable | | | 194,788 | | | | 305,473 | |
| Fuel inventory - at average cost | | | 26,967 | | | | 23,249 | |
| Materials and supplies - at average cost | | | 121,289 | | | | 114,075 | |
| Deferred nuclear refueling outage costs | | | 5,953 | | | | 21,066 | |
| Prepayments and other | | | 7,911 | | | | 5,180 | |
| TOTAL | | | 392,594 | | | | 493,888 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliate preferred membership interests | | | 289,664 | | | | 339,664 | |
| Decommissioning trust funds | | | 477,391 | | | | 420,917 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 165,410 | | | | 164,712 | |
| Storm reserve escrow account | | | 86,984 | | | | 90,249 | |
| Other | | | 13,404 | | | | 12,701 | |
| TOTAL | | | 1,032,853 | | | | 1,028,243 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 7,279,953 | | | | 7,068,657 | |
| Natural gas | | | 135,723 | | | | 129,950 | |
| Construction work in progress | | | 125,448 | | | | 122,051 | |
| Nuclear fuel | | | 146,768 | | | | 206,031 | |
| TOTAL UTILITY PLANT | | | 7,687,892 | | | | 7,526,689 | |
| Less - accumulated depreciation and amortization | | | 4,003,385 | | | | 3,906,353 | |
| UTILITY PLANT - NET | | | 3,684,507 | | | | 3,620,336 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 171,051 | | | | 173,724 | |
| Other regulatory assets | | | 409,653 | | | | 333,898 | |
| Deferred fuel costs | | | 100,124 | | | | 100,124 | |
| Other | | | 12,337 | | | | 13,506 | |
| TOTAL | | | 693,165 | | | | 621,252 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 5,803,119 | | | $ | 5,763,719 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | ENTERGY GULF STATES LOUISIANA, L.L.C. | | ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| BALANCE SHEETS | BALANCE SHEETS | | BALANCE SHEETS | |
| LIABILITIES AND MEMBERS' EQUITY | | |
| LIABILITIES AND EQUITY | | LIABILITIES AND EQUITY | |
| | | | | | | | | | | | | | | |
| | | December 31, | | | December 31, | |
| | | | 2009 | | | | 2008 | | | 2012 | | | 2011 | |
| | | (In Thousands) | | | (In Thousands) | |
| | | | | | | | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | | | | | | | |
| | | | | | | | | | |
| Currently maturing long-term debt | | $ | 11,975 | | | $ | 219,470 | | | $ | 75,000 | | | $ | 60,000 | |
| Accounts payable: | | | | | | | | | | | | | | | | |
| Associated companies | | | 52,622 | | | | 155,147 | | | | 89,377 | | | | 73,305 | |
| Other | | | 91,604 | | | | 162,319 | | | | 97,509 | | | | 101,009 | |
| Customer deposits | | | 45,645 | | | | 40,484 | | | | 48,265 | | | | 49,734 | |
| Taxes accrued | | | - | | | | 418 | | | | 21,021 | | | | 107,367 | |
| Accumulated deferred income taxes | | | 12,219 | | | | - | | | | 22,249 | | | | 5,107 | |
| Interest accrued | | | 24,709 | | | | 30,112 | | | | 25,437 | | | | 26,084 | |
| Deferred fuel costs | | | 42,351 | | | | 91,976 | | | | 948 | | | | 97,178 | |
| Obligations under capital leases | | | 30,387 | | | | 24,368 | | |
| Pension and other postretirement liabilities | | | 8,021 | | | | 7,479 | | | | 7,803 | | | | 7,911 | |
| Gas hedge contracts | | | 263 | | | | 20,184 | | | | 2,620 | | | | 8,572 | |
| System agreement cost equalization | | | 10,000 | | | | 67,000 | | |
| Other | | | 8,790 | | | | 9,220 | | | | 11,999 | | | | 15,294 | |
| TOTAL | | | 338,586 | | | | 828,177 | | | | 402,228 | | | | 551,561 | |
| | | | | | | | | | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 1,345,984 | | | | 1,308,449 | | | | 1,403,195 | | | | 1,368,563 | |
| Accumulated deferred investment tax credits | | | 88,246 | | | | 91,634 | | | | 78,312 | | | | 81,520 | |
| Obligations under capital leases | | | 126,226 | | | | 116,321 | | |
| Other regulatory liabilities | | | 47,423 | | | | 22,007 | | | | 103,444 | | | | 75,721 | |
| Decommissioning and asset retirement cost liabilities | | | 321,158 | | | | 222,909 | | | | 380,822 | | | | 359,792 | |
| Accumulated provisions | | | 14,669 | | | | 13,896 | | | | 97,230 | | | | 99,033 | |
| Pension and other postretirement liabilities | | | 234,473 | | | | 188,390 | | | | 416,220 | | | | 332,672 | |
| Long-term debt | | | 1,614,366 | | | | 1,827,859 | | | | 1,442,429 | | | | 1,482,430 | |
| Long-term payables - associated companies | | | 34,340 | | | | 88,031 | | | | 29,510 | | | | 31,254 | |
| Other | | | 28,952 | | | | 17,145 | | | | 66,725 | | | | 47,397 | |
| TOTAL | | | 3,855,837 | | | | 3,896,641 | | | | 4,017,887 | | | | 3,878,382 | |
| | | | | | | | | | | | | | | | | |
| Commitments and Contingencies | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| MEMBERS' EQUITY | | | | | | | | | |
| EQUITY | | | | | | | | | |
| Preferred membership interests without sinking fund | | | 10,000 | | | | 10,000 | | | | 10,000 | | | | 10,000 | |
| Members' equity | | | 1,473,930 | | | | 1,352,408 | | |
| Member's equity | | | | 1,438,233 | | | | 1,393,386 | |
| Accumulated other comprehensive loss | | | (42,171 | ) | | | (30,265 | ) | | | (65,229 | ) | | | (69,610 | ) |
| TOTAL | | | 1,441,759 | | | | 1,332,143 | | | | 1,383,004 | | | | 1,333,776 | |
| | | | | | | | | | | | | | | | | |
| TOTAL LIABILITIES AND MEMBERS' EQUITY | | $ | 5,636,182 | | | $ | 6,056,961 | | |
| TOTAL LIABILITIES AND EQUITY | | | $ | 5,803,119 | | | $ | 5,763,719 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| | | | | | | | | |
| |
| STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | | | | Common Equity | | | | |
| | | Preferred Membership Interests | | | Member's Equity | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 10,000 | | | $ | 1,445,425 | | | $ | (42,171 | ) | | $ | 1,413,254 | |
| Net income | | | - | | | | 174,319 | | | | - | | | | 174,319 | |
| Other comprehensive income | | | - | | | | - | | | | 1,867 | | | | 1,867 | |
| Dividends/distributions declared on common equity | | | - | | | | (124,300 | ) | | | - | | | | (124,300 | ) |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (827 | ) | | | - | | | | (827 | ) |
| Other | | | - | | | | (24 | ) | | | - | | | | (24 | ) |
| Balance at December 31, 2010 | | $ | 10,000 | | | $ | 1,494,593 | | | $ | (40,304 | ) | | $ | 1,464,289 | |
| Net income | | | - | | | | 201,604 | | | | - | | | | 201,604 | |
| Other comprehensive loss | | | - | | | | - | | | | (29,306 | ) | | | (29,306 | ) |
| Dividends/distributions declared on common equity | | | - | | | | (301,950 | ) | | | - | | | | (301,950 | ) |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (825 | ) | | | - | | | | (825 | ) |
| Other | | | - | | | | (36 | ) | | | - | | | | (36 | ) |
| Balance at December 31, 2011 | | $ | 10,000 | | | $ | 1,393,386 | | | $ | (69,610 | ) | | $ | 1,333,776 | |
| Net income | | | - | | | | 158,977 | | | | - | | | | 158,977 | |
| Member contribution | | | - | | | | 1,000 | | | | - | | | | 1,000 | |
| Other comprehensive income | | | - | | | | - | | | | 4,381 | | | | 4,381 | |
| Dividends/distributions declared on common equity | | | - | | | | (114,200 | ) | | | - | | | | (114,200 | ) |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (825 | ) | | | - | | | | (825 | ) |
| Other | | | - | | | | (105 | ) | | | - | | | | (105 | ) |
| Balance at December 31, 2012 | | $ | 10,000 | | | $ | 1,438,233 | | | $ | (65,229 | ) | | $ | 1,383,004 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| STATEMENTS OF MEMBERS' EQUITY AND COMPREHENSIVE INCOME | |
| | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| MEMBERS' EQUITY | | | | | | | | | | | | | | | | | | |
| Members' Equity - Beginning of period | | $ | 1,352,408 | | | | | | $ | 1,312,701 | | | | | | $ | 2,225,465 | | | | |
| Add: | | | | | | | | | | | | | | | | | | | | | |
| Net Income | | | 153,047 | | | $ | 153,047 | | | | 144,767 | | | $ | 144,767 | | | | 192,779 | | | $ | 192,779 | |
| Other | | | - | | | | | | | | - | | | | | | | | 479 | | | | | |
| Total | | | 153,047 | | | | | | | | 144,767 | | | | | | | | 193,258 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividends/distributions declared: | | | | | | | | | | | | | | | | | | | | | | | | |
| Common equity | | | 30,700 | | | | | | | | 104,200 | | | | | | | | 97,800 | | | | | |
| Preferred membership interests | | | 825 | | | | 825 | | | | 825 | | | | 825 | | | | 3,968 | | | | 3,968 | |
| Entergy Texas, Inc. paid-in capital | | | - | | | | | | | | - | | | | | | | | 631,994 | | | | | |
| Entergy Texas, Inc. shareholders' equity | | | - | | | | | | | | - | | | | | | | | 49,452 | | | | | |
| Entergy Texas, Inc. retained earnings | | | - | | | | | | | | - | | | | | | | | 322,808 | | | | | |
| Other | | | - | | | | | | | | 35 | | | | | | | | - | | | | | |
| Total | | | 31,525 | | | | | | | | 105,060 | | | | | | | | 1,106,022 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Members' Equity - End of period | | $ | 1,473,930 | | | | | | | $ | 1,352,408 | | | | | | | $ | 1,312,701 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| ACCUMULATED OTHER COMPREHENSIVE | | | | | | | | | | | | | | | | | | | | | | | | |
| LOSS (Net of Taxes): | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | $ | (30,265 | ) | | | | | | $ | (22,934 | ) | | | | | | $ | (19,914 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities (net of tax expense (benefit) | | |
| of ($13,111), ($3,068) and $4,550) | | | (11,906 | ) | | | (11,906 | ) | | | (7,331 | ) | | | (7,331 | ) | | | (3,020 | ) | | | (3,020 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at end of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | $ | (42,171 | ) | | | | | | $ | (30,265 | ) | | | | | | $ | (22,934 | ) | | | | |
| Comprehensive Income | | | | | | $ | 140,316 | | | | | | | $ | 136,611 | | | | | | | $ | 185,791 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | ENTERGY GULF STATES LOUISIANA, L.L.C. | | | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Operating revenues (2) | | $ | 1,844,386 | | | $ | 2,733,365 | | | $ | 3,534,612 | | | $ | 3,679,573 | | | $ | 3,367,171 | | | $ | 1,654,894 | | | $ | 2,134,409 | | | $ | 2,097,021 | | | $ | 1,844,386 | | | $ | 2,733,365 | |
Net Income (2) | | $ | 153,047 | | | $ | 144,767 | | | $ | 192,779 | | | $ | 211,988 | | | $ | 206,497 | | | $ | 158,977 | | | $ | 201,604 | | | $ | 174,319 | | | $ | 153,281 | | | $ | 131,888 | |
Total assets (3) | | $ | 5,636,182 | | | $ | 6,056,961 | | | $ | 6,072,691 | | | $ | 7,786,677 | | | $ | 7,809,497 | | | $ | 5,803,119 | | | $ | 5,763,719 | | | $ | 5,690,376 | | | $ | 5,522,751 | | | $ | 6,010,721 | |
| Long-term obligations (1), (3) | | $ | 1,740,592 | | | $ | 1,944,180 | | | $ | 1,756,087 | | | $ | 2,417,480 | | | $ | 2,392,804 | | |
| Long-term obligations (1) | | | $ | 1,442,429 | | | $ | 1,482,430 | | | $ | 1,584,332 | | | $ | 1,740,592 | | | $ | 1,944,180 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | | | (Dollars In Millions) | |
| Electric Operating Revenues (2): | | | | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 393 | | | $ | 554 | | | $ | 1,042 | | | $ | 1,122 | | | $ | 960 | | | $ | 389 | | | $ | 479 | | | $ | 498 | | | $ | 393 | | | $ | 554 | |
| Commercial | | | 354 | | | | 520 | | | | 817 | | | | 883 | | | | 734 | | | | 349 | | | | 416 | | | | 426 | | | | 354 | | | | 520 | |
| Industrial | | | 383 | | | | 672 | | | | 1,035 | | | | 1,150 | | | | 1,014 | | | | 392 | | | | 490 | | | | 489 | | | | 383 | | | | 672 | |
| Governmental | | | 18 | | | | 25 | | | | 45 | | | | 49 | | | | 41 | | | | 18 | | | | 22 | | | | 21 | | | | 18 | | | | 25 | |
| Total retail | | | 1,148 | | | | 1,771 | | | | 2,939 | | | | 3,204 | | | | 2,749 | | | | 1,148 | | | | 1,407 | | | | 1,434 | | | | 1,148 | | | | 1,771 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 475 | | | | 643 | | | | 233 | | | | 145 | | | | 186 | | | | 377 | | | | 562 | | | | 463 | | | | 475 | | | | 643 | |
| Non-associated companies | | | 105 | | | | 181 | | | | 196 | | | | 199 | | | | 188 | | | | 34 | | | | 52 | | | | 79 | | | | 105 | | | | 181 | |
| Other | | | 49 | | | | 38 | | | | 80 | | | | 47 | | | | 167 | | | | 47 | | | | 49 | | | | 40 | | | | 49 | | | | 38 | |
| Total | | $ | 1,777 | | | $ | 2,633 | | | $ | 3,448 | | | $ | 3,595 | | | $ | 3,290 | | | $ | 1,606 | | | $ | 2,070 | | | $ | 2,016 | | | $ | 1,777 | | | $ | 2,633 | |
| Billed Electric Energy Sales (GWh) (2): | | | | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 5,090 | | | | 4,888 | | | | 10,215 | | | | 10,110 | | | | 10,024 | | | | 5,176 | | | | 5,383 | | | | 5,538 | | | | 5,090 | | | | 4,888 | |
| Commercial | | | 5,058 | | | | 4,973 | | | | 8,980 | | | | 8,838 | | | | 8,486 | | | | 5,287 | | | | 5,239 | | | | 5,274 | | | | 5,058 | | | | 4,973 | |
| Industrial | | | 7,601 | | | | 8,416 | | | | 15,012 | | | | 15,065 | | | | 14,967 | | | | 8,890 | | | | 9,041 | | | | 8,801 | | | | 7,601 | | | | 8,416 | |
| Governmental | | | 213 | | | | 215 | | | | 448 | | | | 454 | | | | 441 | | | | 228 | | | | 222 | | | | 210 | | | | 213 | | | | 215 | |
| Total retail | | | 17,962 | | | | 18,492 | | | | 34,655 | | | | 34,467 | | | | 33,918 | | | | 19,581 | | | | 19,885 | | | | 19,823 | | | | 17,962 | | | | 18,492 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 7,084 | | | | 6,490 | | | | 2,488 | | | | 3,259 | | | | 3,213 | | | | 7,727 | | | | 8,595 | | | | 8,516 | | | | 7,084 | | | | 6,490 | |
| Non-associated companies | | | 2,546 | | | | 2,524 | | | | 2,900 | | | | 2,896 | | | | 2,804 | | | | 941 | | | | 1,013 | | | | 1,705 | | | | 2,546 | | | | 2,524 | |
| Total | | | 27,592 | | | | 27,506 | | | | 40,043 | | | | 40,622 | | | | 39,935 | | | | 28,249 | | | | 29,493 | | | | 30,044 | | | | 27,592 | | | | 27,506 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | | (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | | |
| (2) Entergy Gulf States Louisiana's income statements for the years ended December 31, 2008 and 2009 reflect the effects of the separation of the Texas business. Entergy Gulf States Louisiana's income statements for the years ended December 31, 2005, 2006, and 2007 include the operations of Entergy Texas. | | |
| (3) Entergy Gulf States Louisiana's balance sheets as of December 31, 2009, 2008, and 2007 reflect the effects of the separation of the Texas business. Entergy Gulf States Louisiana's balance sheets as of December 31, 2005 and 2006 include the operations of Entergy Texas. | | |
| | | | | | | | | | | | | | | | | | | | | | |
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
Plan to Spin Off the Utility’s Transmission Business
See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt and preferred securities.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy Louisiana’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Louisiana’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $220 million. Entergy Louisiana is considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. In January 2013, Entergy Louisiana drew all of its $187 million funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy Louisiana recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Louisiana recorded corresponding regulatory assets of approximately $76 million and construction work in progress of approximately $144 million. Entergy Louisiana recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Louisiana has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Louisiana is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Results of Operations
Net Income
20092012 Compared to 20082011
Net income decreased $192.8 million primarily due to a prior year settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts, which resulted in a $422 million reduction in income tax expense in the third quarter 2011. The net income effect was partially offset by a $199 million regulatory charge, which reduced net revenue in 2011 because Entergy Louisiana is sharing the benefit with customers. Partially offsetting the decrease in net income was an IRS tax settlement, in second quarter 2012, related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing, which resulted in a $142.7 million income tax savings, partially offset by a $137.1 million ($84.3 million net-of-tax) regulatory charge, which reduced net revenue in 2012 because Entergy Louisiana is sharing the savings with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlements and savings obligation.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2011 Compared to 2010
Net income increased $75.3$242.5 million primarily due to a lower effectivesettlement with the IRS related to the mark-to-market income tax rate, higher othertreatment of power purchase contracts, which resulted in a $422 million income highertax benefit. The net revenue, and lower other operation and maintenance expenses,income effect was partially offset by higher depreciation and amortization expenses.
2008 Compared to 2007
Net income increased $14.2a $199 million primarily due to lower other operation and maintenance expenses, higher other income, and a lower effective income tax rate, offset by lowerregulatory charge, which reduced net revenue, because a portion of the benefit will be shared with customers. See Notes 3 and higher depreciation8 to the financial statements for additional discussion of the settlement and amortization expenses.benefit sharing.
Net Revenue
20092012 Compared to 20082011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 2012 to 2011.
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 886.2 | |
| Mark-to-market tax settlement sharing | | | 199.5 | |
| Retail electric price | | | 6.7 | |
| Volume/weather | | | (21.4 | ) |
| Louisiana Act 55 financing savings obligation | | | (134.1 | ) |
| Other | | | (3.6 | ) |
| 2012 net revenue | | $ | 933.3 | |
The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in the third quarter 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to mark-to-market income tax treatment of power purchase contracts with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.
The retail electric price variance is primarily due to a special formula rate plan increase effective May 2011 in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. See Note 2 to the financial statements for discussion of the formula rate plan increase.
The volume/weather variance is primarily due to the effect of milder weather as compared to the previous year on residential and commercial sales and the effects of the power outages caused by Hurricane Isaac, partially offset by increased usage in the industrial sector as a result of increased consumption by a large industrial customer in the chemical industry as a result of plant expansion.
The Louisiana Act 55 financing savings obligation sharing variance results from a regulatory charge recorded in the second quarter 2012 because Entergy Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financings with customers. See Note 3 to the financial statements for additional discussion of the settlement and savings obligation.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges
Gross operating revenues decreased primarily due to:
| · | a decrease of $330.3 million in fuel cost recovery revenues primarily due to lower fuel rates. Entergy Louisiana’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements; |
| · | a decrease of $42 million in rider revenues primarily due to higher System Agreement credits in 2012; and |
| · | the decrease related to volume/weather, as discussed above. |
Fuel and purchased power expenses decreased primarily due to a decrease in the average market prices of natural gas and purchased power and a decrease in the recovery from customers of deferred fuel costs.
Other regulatory charges decreased primarily due to a regulatory charge recorded in the third quarter 2011 because Entergy Louisiana is sharing the benefits of a settlement with the IRS related to mark-to-market income tax treatment of power purchase contracts with customers, partially offset by a regulatory charge recorded in the second quarter 2012 because Entergy Louisiana is sharing the savings from an IRS settlement related to the uncertain tax position regarding the Hurricane Katrina and Hurricane Rita Louisiana Act 55 financing with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlements and savings obligation.
2011 Compared to 2010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 20092011 to 2008.2010.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $959.2 |
Volume/weather | | 36.7 |
Retail electric price | | (19.2) |
Other | | 3.3 |
2009 net revenue | | $980.0 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 1,043.7 | |
| Mark-to-market tax settlement sharing | | | (195.9 | ) |
| Volume/weather | | | 11.6 | |
| Retail electric price | | | 32.5 | |
| Other | | | (5.7 | ) |
| 2011 net revenue | | $ | 886.2 | |
The mark-to-market tax settlement sharing variance results from a regulatory charge recorded in the third quarter 2011 because a portion of the benefits of a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts will be shared with customers, slightly offset by the amortization of a portion of that charge beginning in October 2011. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.
The volume/weather variance is primarily due to an increase of 5041,095 GWh, or 4%, in billed electricity usageusage. Usage in all sectors, anthe industrial sector increased primarily as a result of increased consumption by a large customer in the chemical industry as the result of a plant expansion. The increase in unbilled sales volume, includingwas partially offset by the effect of Hurricane Gustav and Hurricane Ike which decreased sales volume in 2008, and the effect of moreless favorable weather.weather on residential sales.
The retail electric price variance is primarily due to a formula rate plan increase effective May 2011. See Note 2 to the financial statements for discussion of the formula rate plan increase.
Other regulatory charges (credits)
Other regulatory charges increased primarily due to a settlement with the IRS related to the mark-to-market income tax treatment of power purchase contracts because a portion of the settlement will be shared with customers. See Notes 3 and 8 to the financial statements for additional discussion of the settlement and benefit sharing.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Variances
2012 Compared to 2011
Other operation and maintenance expenses decreased primarily due to:
| · | · | a credit passed on to customers$17.1 million of transmission investment equalization expenses recorded in the fourth quarter 2011 as a result of a billing adjustment related to prior transmission costs (for the Act 55 storm cost financing;approximate period of 1996-2011) allocable to Entergy Louisiana under the System Agreement; |
| · | a net decrease of $7.3 million in fossil-fueled generation expenses due to an overall lower scope of outages compared to prior year; |
| · | the formula rate plan effective August 2008deferral, as approved by the LPSC and the FERC, of costs related to remove interim storm cost recovery upon the Act 55 financingtransition and implementation of stormjoining the MISO RTO, which reduced expenses by $5.2 million; and |
| · | a decrease of $2.7 million as a result of lower write-offs of uncollectible accounts in 2012. |
The decrease was partially offset by:
| · | an increase of $11.2 million in compensation and benefits costs as well as the storm damage accrual. A portion of the decrease is offsetprimarily due to decreasing discount rates and changes in other operationcertain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and maintenance expenses. See Note 211 to the financial statements for further discussion of benefits costs; and |
| · | $6.7 million of costs incurred in 2012 related to the formulaplanned spin-off and merger of the transmission business. |
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the acquisition of the Acadia Unit 2 in April 2011.
Interest expense increased primarily due to:
| · | cessation in 2011 of interest on transmission credits per a FERC order relating to an interconnection and operating agreement between a power producer and Entergy Louisiana; |
| · | the issuance of $200 million of 4.8% Series first mortgage bonds in March 2011; |
| · | the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon rate plan;of 2.04% in September 2011; |
| · | the issuance of $250 million of 1.875% Series first mortgage bonds in January 2012; and |
| · | · | a formula rate plan provisionthe issuance of $12.9$200 million recordedof 5.25% Series first mortgage bonds in the third quarter 2009 for refunds made to customers in November 2009 in accordance with a settlement approved by the LPSC. See Note 2 to the financial statements for further discussion of the settlement.July 2012. |
The decrease was offset by an interruptible load provision of $13.4 million recorded in 2008 for rate refunds that occurred in August and September 2009 and formula rate plan increases effective November 2009.
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
2011 Compared to 2010
ReferOther operation and maintenance expenses increased primarily due to "an increase of $17.1 million in transmission investment equalization expenses as a result of a billing adjustment recorded in the fourth quarter 2011 related to prior transmission costs (for the approximate period of 1996-2011) allocable to Entergy Louisiana under the System Agreement and an increase of $17.5 million in fossil-fueled generation expenses due to an overall higher scope of outages compared to prior year and the addition of Acadia Unit 2 in April 2011.
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS – Other income increased primarily due to an increase of $10.8 million in distributions earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received from the Act 55 storm cost financing and an increase in the allowance for equity funds used during construction due to more construction work in progress in 2011. See “Hurricane RitaGustav and Hurricane KatrinaIke"” below and Note 2 to the financial statements for a discussion of the interim recovery of storm costs and the Act 55 storm cost financing.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)Income Taxes
Gross operating revenues decreasedThe effective income tax rates for 2012, 2011, and 2010 were (84.7%), (357.0%), and 22.3%, respectively. The effective income tax rate of (84.7%) for 2012 was primarily due to the settlement of the tax treatment of the Louisiana Act 55 financing of the Hurricane Katrina and Hurricane Rita storm costs and the reversal of the provision for the uncertain tax positions related to that item. The decline in the rate for 2011 is primarily due to the reversal in the third quarter 2011 for uncertain tax positions resulting from a decreasesettlement with the IRS related to the mark-to-market income tax treatment of $763.4power purchase contracts. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rates and for a discussion of the IRS settlement and audits.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2012, 2011, and 2010 were as follows.
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | $ | 878 | | | $ | 123,254 | | | $ | 151,849 | |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | | | | | | | | | | |
| Operating activities | | | 447,698 | | | | 479,342 | | | | 932,334 | |
| Investing activities | | | (850,866 | ) | | | (811,203 | ) | | | (861,329 | ) |
| Financing activities | | | 432,376 | | | | 209,485 | | | | (99,600 | ) |
| Net increase (decrease) in cash and cash equivalents | | | 29,208 | | | | (122,376 | ) | | | (28,595 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 30,086 | | | $ | 878 | | | $ | 123,254 | |
Operating Activities
Net cash provided by operating activities decreased $31.6 million in fuel cost recovery revenues2012 primarily due to decreased recovery of fuel costs due to a lower fuel ratesrate for the period, Hurricane Isaac storm restoration spending in 2012, and a decreasean increase of $108.1$22.9 million in rider revenues.interest paid resulting from the increase in interest expense, as discussed above. The decrease was partially offset by an increasea decrease of $36.7$31.8 million relatedin pension contributions and the purchase in 2011 of $28.1 million of fuel oil from System Fuels because System Fuels will no longer procure fuel oil for the Utility companies. See “Critical Accounting Estimates” below and Note 11 to volume/weather, as discussed above.the financial statements for a discussion of qualified pension and other postretirement benefits.
Fuel and purchased power expensesNet cash provided by operating activities decreased $453 million in 2011 primarily due to decreasesproceeds of $462 million received in 2010 from the average market prices of natural gas and purchased power and a decrease in the recovery from customers of deferred fuel costs.
Other regulatory charges decreased primarily due to the amortization of deferred capacity charges, which ceased in August 2009,LURC as a result of the May 2006 formula rate plan filing with the LPSC, the recognition of interimAct 55 storm cost recoveries that ceased in July 2008 with the Act 55 financing of storm costs, and thefinancings. The decrease was partially offset by income tax refunds of $39.6 million in 2011 compared to income tax payments of $28.3 million in 2010. See “Hurricane KatrinaGustav and Hurricane Rita insurance proceeds occurring over a twelve-month period. SeeIke” below and Note 2 to the financial statements for a discussion of the formula rate plan, the interim recovery of storm costs, and the Act 55 storm cost financing.
2008 Compared to 2007
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses,financings. In 2011, Entergy Louisiana received tax cash refunds in accordance with the Entergy Corporation and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysisSubsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds primarily result from a decrease in 2010 taxable income from what was previously estimated because of the recognition of additional repair expenses for tax purposes associated with a tax accounting change filed in net revenue comparing 2008 to 2007.2010.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $991.1 |
Retail electric price | | (17.1) |
Purchased power capacity | | (12.0) |
Net wholesale revenue | | (7.4) |
Other | | 4.6 |
2008 net revenue | | $959.2 |
The retail electric price variance is primarily due to the cessation of the interim storm recovery through the formula rate plan upon the Act 55 financing of storm costs and a credit passed on to customers as a result of the Act 55 storm cost financing, partially offset by increases in the formula rate plan effective October 2007. Refer to "Hurricane Rita and Hurricane Katrina" and "State and Local Rate Regulation" below for a discussion of the interim recovery of storm costs, the Act 55 storm cost financing, and the formula rate plan filing.
The purchased power capacity variance is due to the amortization of deferred capacity costs effective September 2007 as a result of the formula rate plan filing in May 2007. Purchased power capacity costs are offset in base revenues due to a base rate increase implemented to recover incremental deferred and ongoing purchased power capacity charges. See "State and Local Rate Regulation" below for a discussion of the formula rate plan filing.
The net wholesale revenue variance is primarily due to provisions recorded for potential rate refunds related to the treatment of interruptible load in pricing Entergy System affiliate sales.
Entergy Louisiana, LLC and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Gross operating revenues and fuel and purchased power expensesInvesting Activities
Gross operating revenuesNet cash used in investing activities increased $39.7 million in 2012 primarily due to an increase of $364.7 million in fuel cost recovery revenues due to higher fuel rates offset by decreased usage. to:
| · | an increase in fossil construction expenditures due to spending on the Ninemile Unit 6 self-build project; |
| · | an increase in nuclear construction expenditures due to the Waterford 3 steam generator replacement project in 2012. The increase is partially offset by various nuclear projects in 2011; |
| · | higher distribution construction expenditures due to Hurricane Isaac; and |
The increase was partially offset by:
| · | the purchase of the Acadia Unit 2 for approximately $300 million in April 2011; |
| · | a decrease in nuclear fuel activity because of variations from year to year in the timing and pricing of fuel reload requirements in the Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; |
| · | a decrease in transmission construction expenditures due to increased work performed in 2011; and |
| · | receipts of $13.7 million in 2012 from the storm reserve escrow account. |
Increases in Entergy Louisiana’s receivable from the money pool are a use of cash flow, and Entergy Louisiana’s receivable from the money pool increased by a decrease of $56.8$9.4 million in gross wholesale revenue due2012 compared to a decreasedecreasing by $49.9 million in System Agreement rough production cost equalization credits.2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Fuel and purchased power expenses increasedNet cash used in investing activities decreased $50.1 million in 2011 primarily due to increases in the average market prices of natural gas and purchased power, partially offset by a decrease in the recovery from customers of deferred fuel costs.to:
Other Income Statement Variances
2009 Compared to 2008
Other operation and maintenance expenses decreased primarily due to a decrease of $6.5 million in payroll-related costs and a decrease of $6.4 million in loss reserves in 2009, including a decrease in the storm damage reserve. The decrease was partially offset by an increase of $9.0 million in nuclear expenses due to higher nuclear labor and contract costs.
Depreciation and amortization expenses increased primarily due to an increase in plant in service.
Other income increased primarily due to:
| · | an increasethe investment in 2010 of $25$262.4 million in distributions earned on preferred membership interests purchased from Entergy Holdings Company withaffiliate securities and the proceeds received frominvestment of $200 million in the storm reserve escrow account as a result of the Act 55 storm cost financing.financings. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS – “Hurricane RitaGustav and Hurricane KatrinaIke"” below and Note 2 to the financial statements for a discussion of the Act 55 storm cost financing; and
|
| · | an increase in the allowance for equity funds used during construction due to more construction work in progress throughout 2009.money pool activity. |
Interest and other charges increased slightly primarily due to the issuance of $300 million of 6.50% Series first mortgage bonds in August 2008 and the issuance of $400 million of 5.40% Series first mortgage bonds in November 2009, substantiallyThe increase was partially offset by an increase in the allowance for borrowed funds used during construction due to more construction work in progress in 2009.
2008 Compared to 2007
Other operation and maintenance expenses decreased primarily due to:by:
| · | a decreasethe purchase of $9.3the Acadia Power Plant for approximately $300 million in nuclear spending due to a prior year non-refueling outage; |
· | a decrease of $8.6 million in payroll-related costs; |
· | a decrease of $8.1 million in loss reserves for storm damage in 2008 because of completion of the Act 55 storm cost financing; and |
· | a decrease of $5.7 million in customer service costs primarily as a result of write-offs in 2007 of uncollectible customer accounts. |
The decrease was partially offset by an increase of $4.5 million in transmission spending due to additional costs related to compliance, substation maintenance, and line and vegetation maintenance and an increase of $4.3 million in fossil expenses due to a fossil plant maintenance outage in 2008.
Depreciation and amortization expenses increased primarily due to:
· | a revision in the third quarter 2007 related to depreciation on storm cost-related assets. Recovery of the cost of those assets will now be through the Act 55 financing of storm costs as approved by the LPSC in the third quarter 2007. See "Hurricane Rita and Hurricane Katrina" below for a discussion of the Act 55 storm cost financing;
|
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
· | a revision in the fourth quarter 2008 of estimated depreciable lives involving certain intangible assets in accordance with formula rate plan treatment;April 2011; and |
| · | an increase in plant in service. |
Other income increased primarily due to:
· | distributions of $29.5 million earned on preferred stock purchased from Entergy Holdings Company with the proceeds received from the Act 55 Storm Cost Financings; |
· | interest earned on the deferrednuclear fuel balance; |
· | carrying charges on storm restoration costs approved by the LPSC; and |
· | an increase in the allowance for equity funds used during construction due to more construction work in progress in 2008. |
See "Hurricane Rita and Hurricane Katrina" below for a discussion of the Act 55 storm cost financing.
Income Taxes
The effective income tax rates for 2009, 2008, and 2007 were 16.2%, 31.0%, and 36.8%, respectively. The decline in the rate for 2009 is primarily due to the reallocation of Entergy Corporation consolidated tax benefits based on the partial settlement of IRS audits of prior tax years, the exclusion of dividend income from Entergy Louisiana's preferred membership interest in Entergy Holdings Company, LLC, and the flow-through of the equity component of AFUDC. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate and for a discussion of the IRS audits.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008, and 2007 were as follows:
| | | | 2009 | | 2008 | | 2007 |
| | | | (In Thousands) |
| | | | | | | | |
| Cash and cash equivalents at beginning of period | | $138,918 | | $300 | | $2,743 |
| | | | | | | | |
| Cash flow provided by (used in): | | | | | | |
| | Operating activities | | 87,879 | | 1,082,592 | | 353,438 |
| | Investing activities | | (436,251) | | (1,170,994) | | (297,460) |
| | Financing activities | | 361,303 | | 227,020 | | (58,421) |
| | Net increase (decrease) in cash and cash equivalents | | 12,931 | | 138,618 | | (2,443) |
| | | | | | | | |
| Cash and cash equivalents at end of period | | $151,849 | | $138,918 | | $300 |
Operating Activities
Cash flow provided by operating activities decreased $994.7 million primarily due to storm cost proceeds of $679 million received in 2008 from the LURC as a result of the Act 55 storm cost financing and income tax payments of $223.6 million in 2009 compared to income tax refunds of $12.7 million in 2008. See Note 3 to the financial statements for a discussion of the tax payments in 2009.
Cash flow provided by operating activities increased $729.2 million in 2008 compared to 2007 primarily due to storm cost proceeds of $679 million received from the LURC as a result of the Act 55 storm cost financing and income tax refunds of $12.7 million in 2008 compared to income tax payments of $119.1 million in 2007. The increase was partially offset by a lower amount of fuel costs recovered in 2008 than in 2007. See "Hurricane Rita and Hurricane Katrina" below for a discussion of the storm cost financings.
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities decreased $734.7 million in 2009 compared to 2008 primarily due to:
· | the investment in 2008 of $545 million in affiliate securities as a resultactivity because of the Act 55 storm cost financing. See "MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS – Hurricane Ritatiming of refueling outages and Hurricane Katrina" and Note 2 to the financial statements for a discussionpurchase of nuclear fuel inventory from System Fuels because the Act 55 storm cost financing;
Utility companies will now purchase nuclear fuel throughout the nuclear fuel procurement cycle, rather than purchasing it from System Fuels at the time of refueling. |
· | higher construction expenditures in 2008 due to Hurricane Gustav and Hurricane Ike; |
· | the suspension of the Little Gypsy repowering project in 2009. See "Little Gypsy Repowering Project" below for a discussion of the suspension;
|
· | lower transmission construction expenditures in 2009; and |
The decrease was partially offset by increased nuclear construction expenditures primarily due to the Waterford 3 steam generator replacement project, the dry fuel storage project, security upgrades, and the reactor coolant pump upgrades project.
Decreases in Entergy Louisiana'sLouisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana'sLouisiana’s receivable from the money pool decreased $8.4by $49.9 million in 20092011 compared to increasing $61.2decreasing by $2.9 million in 2008. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries' need for external short-term borrowings.2010.
Financing Activities
Net cash flow used in investingprovided by financing activities increased $873.5$222.9 million in 2008 compared to 20072012 primarily due to:
| · | the investmentnet cash issuances of $545$650 million of first mortgage bonds in affiliate securities as a result2012 compared to net cash issuances of the Act 55 storm cost financings. See "Hurricane Rita and Hurricane Katrina" below for a discussion$200 million of the storm cost financings;
first mortgage bonds in 2011; |
| · | increased construction expendituresa decrease of $342.6 million in 2008 duecommon equity dividends in 2012; |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
| · | the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon rate of 2.04% in September 2011; |
| · | the issuance of the $25 million 3.25% Series G note by the nuclear fuel company variable interest entity in August 2012; |
| · | the issuance of the $20 million 3.30% Series F note by the nuclear fuel company variable interest entity in March 2011; |
| · | a principal payment of $25.6 million in 2012 for the Senior Secured Investment Recovery bonds; |
| · | an increase in borrowings of $10.3 million on the nuclear fuel company variable interest entity’s credit facility in 2012 compared to Hurricane Gustavan increase in borrowings of $21.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011; |
| · | a principal payment of $25.3 million in 2012 for the Waterford 3 sale-leaseback obligation compared to a principal payment of $35.5 million in 2011; |
| · | borrowing of $50 million on Entergy Louisiana’s credit facility in 2011 and Hurricane Ike, the Little Gypsy Unit 3 repowering project, and various nuclear projects;payment on the credit borrowing of $50 million in 2012; and |
Increases in Entergy Louisiana's receivable from the money pool are a use of cash flow, and Entergy Louisiana's receivable from the money pool increased by $61.2 million in 2008.
Financing Activities
Entergy Louisiana's cash flow provided by financing activities increased $134.3 million in 2009 compared to 2008 primarily due to the issuance of $400 million of 5.40% Series first mortgage bonds in November 2009 compared to the issuance of $300 million of 6.50% Series first mortgage bonds in August 2008 and the repurchase in 2008 of $60 million of Auction Rate governmental bonds, partially offset by an increase of $20.6 million in common equity distributions paid in 2009.
Entergy Louisiana's financings activities provided $227.0 million of cash in 2008 compared to using $58.4 million of cash in 2007 primarily due to the issuance of $300 million of 6.50% Series first mortgage bonds in August 2008 and money pool activity, partially offset by the repurchase, prior to maturity, of $60 million of Auction Rate governmental bonds, which are being held for remarketing at a later date.
DecreasesDecrease in Entergy Louisiana's payable to the money pool are a use of cash flow, and Entergy Louisiana'sLouisiana’s payable to the money pool decreased $2.8by $118.4 million in 2008 and $51.32012 compared to increasing by $118.4 million in 2007.2011.
Entergy Louisiana’s financing activities provided cash of $209.5 million in 2011 compared to using cash of $99.6 million in 2010 primarily due to:
| · | the issuance by Entergy Louisiana Investment Recovery Funding, L.L.C., a wholly owned subsidiary of Entergy Louisiana, of $207.2 million of senior secured investment recovery bonds with a coupon of 2.04% in September 2011; |
| · | net cash issuances of $200 million of first mortgage bonds in 2011 compared to net cash redemptions of $120 million of first mortgage bonds in 2010; |
| · | an increase in borrowings on the nuclear fuel company variable interest entity’s credit facility; |
| · | borrowings of $50 million on its credit facility in 2011; |
| · | the retirement of the $30 million Series D note by the nuclear fuel company variable interest entity in January 2010; |
| · | the issuance of the $20 million Series F note by the nuclear fuel company variable interest entity in March 2011; |
| · | common equity dividends of $358.2 million paid in 2011; |
| · | the issuance in October 2010 of $115 million of 5% Revenue Bonds Series 2010; and |
| · | a principal payment of $35.5 million in 2011 for the Waterford 3 sale-leaseback obligation compared to a principal payment of $17.3 million in 2010. |
Increases in Entergy Louisiana’s payable to the money pool are a source of cash flow, and Entergy Louisiana’s payable to the money pool increased by $118.4 million in 2011.
See Note 5 to the financial statements for details of long-term debt.
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
Capital Structure
Entergy Louisiana'sLouisiana’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital for Entergy Louisiana as of December 31, 2009 is primarily due to the issuance of $400 million of 5.40% Series first mortgage bonds in November 2009.
| | | December 31, 2009 | | December 31, 2008 |
| | | | | |
| Net debt to net capital | | 47.8% | | 43.6% |
| Effect of subtracting cash from debt | | 2.1% | | 2.5% |
| Debt to capital | | 49.9% | | 46.1% |
| | | December 31, 2012 | | December 31, 2011 |
| | | | | |
| Debt to capital | | 48.4% | | 47.2% |
| Effect of excluding securitization bonds | | (1.6%) | | (2.3%) |
| Debt to capital, excluding securitization bonds (1) | | 46.8% | | 44.9% |
| Effect of subtracting cash | | (0.3%) | | -% |
| Net debt to net capital, excluding securitization bonds (1) | | 46.5% | | 44.9% |
| (1) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt and members'members’ equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana'sLouisiana’s financial condition.
Uses of Capital
Entergy Louisiana requires capital resources for:
| · | construction and other capital investments; |
| · | debt and preferred equity maturities;maturities or retirements; |
| · | working capital purposes, including the financing of fuel and purchased power costs; and |
| · | distribution and interest payments. |
Following are the amounts of Entergy Louisiana'sLouisiana’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:obligations.
| | 2010 | | 2011-2012 | | 2013-2014 | | After 2014 | | Total | | 2013 | | 2014-2015 | | 2016-2017 | | After 2017 | | Total |
| | (In Millions) | (In Millions) |
| Planned construction and | | | | | | | | | | | |
| capital investment (1) | $503 | | $1,280 | | N/A | | N/A | | $1,783 | | |
| Planned construction and capital investment (1): | | Planned construction and capital investment (1): | | | | | | | |
| Generation | | $530 | | $306 | | N/A | | N/A | | $836 |
| Transmission | | 117 | | 201 | | N/A | | N/A | | 318 |
| Distribution | | 130 | | 233 | | N/A | | N/A | | 363 |
| Other | | 19 | | 79 | | N/A | | N/A | | 98 |
| Total | | $796 | | $819 | | N/A | | N/A | | $1,615 |
| Long-term debt (2) | $329 | | $250 | | $332 | | $2,056 | | $2,967 | | $152 | | $603 | | $404 | | $3,689 | | $4,848 |
| Operating leases | $9 | | $15 | | $11 | | $6 | | $41 | | $11 | | $18 | | $8 | | $4 | | $41 |
| Purchase obligations (3) | $601 | | $1,302 | | $716 | | $4,389 | | $7,008 | | $600 | | $1,150 | | $975 | | $5,981 | | $8,706 |
| Nuclear fuel lease obligations (4) | $57 | | $65 | | N/A | | N/A | | $122 | | |
| (1) | Includes approximately $152$207 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs, and do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Louisiana, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Vidalia purchased power agreement and the Unit Power Sales Agreement, both of which are discussed in Note 8 to the financial statements. |
(4) | It is expected that additional financing under the lease will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, Entergy Louisiana must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. |
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $27.1$20.7 million to its pension plans and approximately $9.9$10.2 million to other postretirement plans in 2010;2013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the2013. See "Critical Accounting Estimates – Qualified Pension Protection Actand Other Postretirement Benefits" below for a discussion of 2006 rules, effective for the 2008 plan yearqualified pension and beyond, continues to evolve, be interpreted through technical
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Louisiana’s pension contributions in the future.
Also, in addition to the contractual obligations, Entergy Louisiana has $282.1 million of unrecognized taxother postretirement benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.funding.
The planned capital investment estimate for Entergy Louisiana reflects capital required to support existing business and customer growth, including the purchase of Acadia Unit 2Ninemile 6 self-build project and the replacement offinal spending from the Waterford 3 steam generators,generator replacement project, both of which are discussed below, and dry cask spent fuel storage. Entergy'sbelow. Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Management provides more information on long-term debt and preferred stock maturities in NotesNote 5 and 6 to the financial statements.
Acadia Unit 2 Purchase Agreement
In October 2009As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy Louisiana announced that it signed an agreement to acquire Unit 2pays distributions from its earnings at a percentage determined monthly. Entergy Louisiana’s long-term debt indenture contains restrictions on the payment of the Acadia Energy Center, a 580 MW generating unit located near Eunice, La., from Acadia Power Partners, LLC, an independent power producer. The Acadia Energy Center, which entered commercial service in 2002, consists of two combined-cycle gas-fired generating units, each nominally rated at 580 MW. Entergy Louisiana proposes to acquire 100 percent of Acadia Unit 2cash dividends or other distributions on its common and a 50 percent ownership interest in the facility’s common assets for approximately $300 million. In a separate transaction, Cleco Power is acquiring Acadia Unit 1 and the other 50 percent interest in the facility’s common assets. Upon closing the transaction, Cleco Power will serve as operator for the entire facility. Entergy Louisiana has committed to sell one third of the output of Unit 2 to Entergy Gulf States Louisiana in accordance with terms and conditions detailed under the existing Entergy System Agreement.preferred membership interests.
Entergy Louisiana's purchase is contingent upon, among other things, obtaining necessary approvals, including full cost recovery, from various federal and state regulatory and permitting agencies. Closing is expected to occur in late 2010 or early 2011. Entergy Louisiana and Acadia Power Partners also have entered into a purchased power agreement for 100 percent of the output of Acadia Unit 2 that is expected to commence on May 1, 2010 and is set to expire at the closing of the acquisition transaction. Entergy Louisiana has filed with the LPSC for approval of the transaction, and no party filed an opposition to the purchase power agreement and it has been forwarded to the LPSC for its review. The parties have agreed to a procedural schedule for the acquisition that would lead to LPSC consideration of the matter at its January 2011 meeting and includes a hearing before the ALJ in September 2010.
Waterford 3 Steam Generator Replacement Project
Entergy Louisiana plansplanned to replace the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, in the spring 2011. Replacement of these components is common to pressurized water reactors throughout the nuclear industry. The nuclear industry continuesIn December 2010, Entergy Louisiana advised the LPSC that the replacement generators would not be completed and delivered by the manufacturer in time to address susceptibilityinstall them during the spring 2011 refueling outage. During the final steps in the manufacturing process, the manufacturer discovered separation of stainless steel cladding from the carbon steel base metal in the channel head of both replacement steam generators (RSGs), in areas beneath and adjacent to stress corrosion crackingthe divider plate. As a result of certain materials associated with these components withinthis damage, the reactor coolant system. The issue is applicablemanufacturer was unable to meet the contractual delivery deadlines, and the RSGs were not installed in the spring 2011. Waterford 3 and is managed in accordanceresumed operations with standard industry practices and guidelines. Routine inspectionsthe original steam generators upon completion of the steam generators during Waterford 3's Fall 2006spring 2011 refueling outage, identified additional degradation of certain tube spacer supports in the steam generators that required repair beyond that anticipated prior to the outage. Corrective measures were successfully implemented to permit continued operationwhich included inspection and maintenance of the original steam generators. While potential future replacement of these components had been contemplated, additional steam generator tube and component degradation necessitates replacement of
Entergy Louisiana LLC
Management's Financial Discussionworked with the RSG manufacturer to fully develop, evaluate, and Analysis
implement repair options, and the steam generators as soon as reasonably achievable. The earliestRSGs were delivered in time for Waterford 3’s fall 2012 refueling outage, which began in October 2012. During the new steam generators can be manufactured and delivered for installation is 2011. A mid-cyclefall 2012 refueling outage performed in 2007 supports Entergy Louisiana's 2011 replacement strategy. TheLouisiana replaced the RSGs, reactor vessel head, and control element drive mechanisms will be replaced atmechanisms. Those components, which together comprised the same time, utilizing the same reactor building construction opening that is necessary for the steam generator replacement. replacement project, were placed in-service in December 2012.
In June 2008, Entergy Louisiana filed with the LPSC for approval of the replacement project, including full cost recovery. Following discovery and the filing of testimony by the LPSC staff and an intervenor, the parties entered into a stipulated settlement of the proceeding. The LPSC unanimously approved the settlement in November 2008. The settlement resolved the following issues: 1) the accelerated degradation of the steam generators is not the result of any imprudence on the part of Entergy Louisiana; 2) the decision to undertake the replacement project at the current estimatedthen-estimated cost of $511 million is in the public interest, is prudent, and would serve the public convenience and necessity; 3) the scope of the replacement project is in the public interest; 4) undertaking the replacement project at the target installation date during the 2011 refueling outage is in the public interest; and 5) the jurisdictional costs determined to be prudent in a future prudence review are eligible for cost recovery, either in an extentionextension or renewal of the formula rate plan or in a full base rate case including necessary proformapro forma adjustments. Upon
In November 2011, the LPSC approved a one-year extension of Entergy Louisiana’s formula rate plan and provided a mechanism to begin recovering the costs of the replacement project in the first billing cycle after it is placed in service. On December 21, 2012, Entergy Louisiana provided notice of the first year revenue requirement associated with the replacement project that would be placed into rates in the January 2013 billing cycle. The estimated revenue requirement included the LPSC-jurisdictional share of the replacement project costs, less (i) a credit for earnings above a 10.25% return on common equity (based on the 2011 test year) for the period following the in-service date, and (ii) a credit for operation and maintenance savings expected from the RSGs. These rates are anticipated to remain in effect until Entergy Louisiana’s rate case filed in February 2013 is resolved. See “State and Local Rate Regulation and Fuel-Cost Recovery” below for additional discussion of the formula rate plan and rate case filings. With completion of the replacement project, the LPSC will undertake a prudence review in connection with a filing to be made by Entergy Louisiana on or before April 30, 2013 with regard to the following aspects of the replacement project: 1) project management; 2) cost controls; 3) success in achieving stated objectives; 4) the costs of the replacement project; and 5) the outage length and replacement power costs.
In July 2009,See “State and Local Rate Regulation and Fuel-Cost Recovery” below for a discussion of the LPSC grantedrenewal of Entergy Louisiana's motion to dismiss, without prejudice,Louisiana’s formula rate plan for the 2011 test year and its application seeking recovery of cash earnings on construction work in progress (CWIP) forprovisions addressing the Waterford 3 steam generator replacement project, acknowledging Entergy Louisiana's right, at any time, to seek cash earnings on CWIP if Entergy Louisiana believes that circumstances or projected circumstances are such that a request for cash earnings on CWIP is merited. The cash earnings on CWIP application had been consolidated with a similar request for the Little Gypsy repowering project, which was also dismissed in response to the same motion.
Entergy Louisiana estimates that it will spend approximately $511 million on this project, including $299 million over the 2010-2011 period.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant, and Entergy Gulf States Louisiana filed subsequently with the LPSC seeking certification to participate in one-third of the project. Petroleum coke and coal would be the unit's primary fuel sources. In July 2007, Entergy Louisiana filed with the LPSC for approval of the repowering project. In addition to seeking a finding that the project is in the public interest, the filing with the LPSC asked that Entergy Louisiana be allowed to recover a portion of the project's financing costs during the construction period.
On March 11, 2009, the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project's economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. On April 1, 2009, Entergy Louisiana complied with the LPSC's directive and recommended that the project be suspended for an extended period of time of three years or more. Entergy Louisiana estimated that its total costs for the project, if suspended, including actual spending to date and estimated contract cancellation costs, would be approximately $300 million. Entergy Louisiana had obtained all major environmental permits required to begin construction. A longer-term suspension places these permits at risk and may adversely affect the project's economics and technological feasibility. On May 22, 2009, the LPSC issued an order declaring that Entergy Louisiana's decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent. In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the project and seeking recovery over a five-year period of the project costs. The parties to the proceeding agreed to a procedural schedule that results in a hearing in October 2010. Entergy Louisiana currently estimates that its total costs for the project, if canceled, will be approximately $215 million, of which approximately $193 million was incurred through December 31, 2009.
Entergy Louisiana, LLC and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. All major permits and approvals required to begin construction have been obtained and construction is in progress.
Under the terms approved by the LPSC, costs may be recovered through Entergy Louisiana’s and Entergy Gulf States Louisiana’s formula rate plans, if one is in effect when the project is placed in service; alternatively, Entergy Gulf States Louisiana and Entergy Louisiana must file rate cases approximately 12 months prior to the expected in-service date.
New Nuclear Development
Entergy Gulf States Louisiana and Entergy Louisiana provided public notice to the LPSC of their intention to makehave been developing and are preserving a filing pursuant to the LPSC's general order that governs the development of new nuclear generation in Louisiana. The project option being developed by the companies is for new nuclear generation at River Bend. Entergy Gulf States Louisiana and Entergy Louisiana, together with Entergy Mississippi, have been engaged inIn the development of options to construct new nuclear generation at the River Bend and Grand Gulf sites. Entergy Gulf States Louisiana and Entergy Louisiana are leading the development at River Bend, and Entergy Mississippi is leading the development at Grand Gulf. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. Infirst quarter 2010, Entergy Gulf States Louisiana and Entergy Louisiana each paid for and will recognizerecognized on its books $24.9 million in costs associated with the development of new nuclear generation at the River Bend site; these costs previously had been recorded on the books of Entergy New Nuclear Utility Development, LLC, a System Energy subsidiary. Entergy Gulf States Louisiana and Entergy Louisiana will share costs going forward on a 50/50 basis, which reflects each company'scompany’s current participation level in the project.
In responseMarch 2010, Entergy Gulf States Louisiana and Entergy Louisiana filed with the LPSC seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. The testimony and legal briefs of the LPSC staff generally support the request of Entergy Gulf States Louisiana and Entergy Louisiana, although other parties filed briefs, without supporting testimony, in opposition to the companies' previous notice, dated August 10, 2009,request. At an evidentiary hearing in October 2011, Entergy Gulf States Louisiana, Entergy Louisiana, and the LPSC openedstaff presented testimony in support of certification of activities to preserve an option for a docket. A procedural schedule will be established afternew nuclear plant at River Bend. The ALJ recommended, however, that the LPSC decline the request of Entergy Gulf States Louisiana and Entergy Louisiana on the basis that the LPSC’s rule on new nuclear development does not apply to activities to preserve an option to develop and on the further grounds that the companies fileimproperly engaged in advanced preparation activities prior to certification. There has been no suggestion that the certification application referredplanning activities or costs incurred were imprudent. At its June 28, 2012 meeting the LPSC voted to uphold the ALJ’s decision and directed that Entergy Gulf States Louisiana and Entergy Louisiana be permitted to seek recovery of these costs in their anticipated, upcoming rate case filings, fully reserving the notice.LPSC’s right to determine the recoverability of such costs in rates. On September 10, 2012, Entergy Gulf States Louisiana and Entergy Louisiana filed a petition for appeal and judicial review of the LPSC’s order with the Louisiana Nineteenth Judicial District Court. A schedule for the appeal has not been established. In their rate cases filed in February 2013, Entergy Gulf States Louisiana and Entergy Louisiana request recovery of their new nuclear generation development costs over a ten-year amortization period, with the costs included in rate base.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Sources of Capital
Entergy Louisiana'sLouisiana’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt or preferred membership interest issuances; and |
| · | bank financing under new and existing facilities. |
Entergy Louisiana may refinance, redeem, or redeemotherwise retire debt and preferred membership interests prior to maturity, to the extent market conditions and interest and distribution rates are favorable.
All debt and common and preferred membership interest issuances by Entergy Louisiana require prior regulatory approval. Preferred membership interest and debt issuances are also subject to issuance tests set forth in corporate charters,its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Louisiana'sLouisiana’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:years.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $52,807 | | $61,236 | | ($2,791) | | ($54,041) |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $9,433 | | ($118,415) | | $49,887 | | $52,807 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Louisiana has a credit facility in the amount of $200 million scheduled to expire in August 2012.March 2017. No borrowings were outstanding under the credit facility as of December 31, 2009.2012. See Note 4 to the financial statements for additional discussion of the credit facilities.
The Entergy Louisiana nuclear fuel company variable interest entity has a credit facility in the amount of $90 million scheduled to expire in July 2013. As of December 31, 2012, $54.7 million was outstanding on the credit facility. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Louisiana obtained short-term borrowing authorization from the FERC under which it may borrow through October 2011,2013, up to the aggregate amount, at any one time outstanding, of $250 million. See Note 4 to the financial statements for further discussion of Entergy Louisiana'sLouisiana’s short-term borrowing limits. Entergy Louisiana has also obtained an order from the FERC authorizing long-term securities issuances through July 2011.2013. Entergy Louisiana has also obtained long-term financing authorization from the FERC that extends through January 2015 for issuances by its nuclear fuel company variable interest entity.
Little Gypsy Repowering Project
In April 2007, Entergy Louisiana announced that it intended to pursue the solid fuel repowering of a 538 MW unit at its Little Gypsy plant. In March 2009 the LPSC voted in favor of a motion directing Entergy Louisiana to temporarily suspend the repowering project and, based upon an analysis of the project’s economic viability, to make a recommendation regarding whether to proceed with the project. This action was based upon a number of factors including the recent decline in natural gas prices, as well as environmental concerns, the unknown costs of carbon legislation and changes in the capital/financial markets. In April 2009, Entergy Louisiana complied with the LPSC’s directive and recommended that the project be suspended for an extended period of time of three years or more. In May 2009 the LPSC issued an order declaring that Entergy Louisiana’s decision to place the Little Gypsy project into a longer-term suspension of three years or more is in the public interest and prudent.
Entergy Louisiana, LLC and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
In October 2009, Entergy Louisiana made a filing with the LPSC seeking permission to cancel the Little Gypsy repowering project and seeking project cost recovery over a five-year period. In June 2010 and August 2010, the LPSC Staff and Intervenors filed testimony. The LPSC Staff (1) agreed that it was prudent to move the project from long-term suspension to cancellation and that the timing of the decision to suspend on a longer-term basis was not imprudent; (2) indicated that, except for $0.8 million in compensation-related costs, the costs incurred should be deemed prudent; (3) recommended recovery from customers over ten years but stated that the LPSC may want to consider 15 years; (4) allowed for recovery of carrying costs and earning a return on project costs, but at a reduced rate approximating the cost of debt, while also acknowledging that the LPSC may consider ordering no return; and (5) indicated that Entergy Louisiana should be directed to securitize project costs, if legally feasible and in the public interest. In the third quarter 2010, in accordance with accounting standards, Entergy Louisiana determined that it was probable that the Little Gypsy repowering project would be abandoned and accordingly reclassified $199.8 million of project costs from construction work in progress to a regulatory asset. A hearing on the issues, except for cost allocation among customer classes, was held before the ALJ in November 2010. In January 2011 all parties participated in a mediation on the disputed issues, resulting in a settlement of all disputed issues, including cost recovery and cost allocation. The settlement provides for Entergy Louisiana to recover $200 million as of March 31, 2011, and carrying costs on that amount on specified terms thereafter. The settlement also provides for Entergy Louisiana to recover the approved project costs by securitization. In April 2011, Entergy Louisiana filed an application with the LPSC to authorize the securitization of the investment recovery costs associated with the project and to issue a financing order by which Entergy Louisiana could accomplish such securitization. In August 2011 the LPSC issued an order approving the settlement and also issued a financing order for the securitization. See Note 5 to the financial statements for a discussion of the September 2011 issuance of the securitization bonds.
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav (and, to a much lesser extent, Hurricane Ike) caused catastrophic damage to Entergy Louisiana'sLouisiana’s service territory. The storms resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. On October 9, 2008, Entergy Louisiana drew all of its $134 million funded storm reserve. On October 15, 2008, the LPSC approved Entergy Louisiana'sLouisiana’s request to defer and accrue carrying costs on unrecovered storm expenditures during the period the company seeks regulatory recovery. The approval was without prejudice to the ultimate resolution of the total amount of prudently incurred storm costs or final carrying costs rate.
Entergy Gulf States Louisiana and Entergy Louisiana filed their Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Gulf States Louisiana and Entergy Louisiana made a supplemental filing to, among other things, recommend recoveryand the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana’s and Entergy Louisiana’s storm costs, storm reserves, and replenishmentissuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Act 55 financings). Entergy Gulf States Louisiana’s and Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm reservescosts were financed primarily by Louisiana Act 55 (passed in 2007) financing.financings, as discussed below. Entergy Gulf States Louisiana and Entergy Louisiana recovered their costs from Hurricane Katrinaalso filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Hurricane Rita primarily by Act 55 financing as discussed below. Onsavings to customers via a Storm Cost Offset rider.
In December 30, 2009, Entergy Gulf States Louisiana and Entergy Louisiana entered into a stipulation agreement with the LPSC Staff that if approved, provides for total recoverable costs of approximately $234 million for Entergy Gulf States Louisiana and $394 million for Entergy Louisiana.Louisiana, including carrying costs. Under this stipulation, Entergy Gulf States Louisiana agrees not to recover $4.4 million and Entergy Louisiana agrees not to recover $7.2 million of their storm restoration spending. The stipulation also permits replenishing Entergy Gulf States Louisiana's storm reserve in the amount of $90 million and Entergy Louisiana's storm reserve in the amount of $200 million when the Act 55 financing isfinancings are accomplished. The parties to the proceeding have agreed to a procedural schedule that includes March/April 2010 hearing dates for both the recoverability and the method of recovery proceedings.
Hurricane Rita and Hurricane Katrina
In August and September 2005, Hurricane Katrina and Hurricane Rita, along with extensive flooding that resulted from levee breaks in and around Entergy Louisiana's service territory, caused catastrophic damage. The storms and flooding resulted in widespread power outages; significant damage to distribution, transmission, and generation infrastructure; and the temporary loss of sales and customers due to mandatory evacuations and destruction of homes and businesses due to wind, rain, and extended periods of flooding. Entergy pursued a broad range of initiatives to recover storm restoration and business continuity costs and incremental losses. Initiatives included obtaining reimbursement of certain costs covered by insurance and pursuing recovery through existing or new rate mechanisms regulated by the FERC and local regulatory bodies, in combination with securitization.
Insurance Claims
Entergy has received a total of $317 million as of December 31, 2009 on its Hurricane Katrina and Hurricane Rita insurance claims, including the settlements of its Hurricane Katrina claims with each of its two excess insurers. Of the $317 million received, $45 million was allocated to Entergy Louisiana. Entergy has substantially completed its insurance recoveries related to Hurricane Katrina and Hurricane Rita.
Storm Cost Financings
In March 2008,and April 2010, Entergy Gulf States Louisiana, Entergy Louisiana, and the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, filed at the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Gulf States Louisiana and Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Legislature (Act 55 financings). The Act 55 financings are expected to produce additional customer benefits as compared to Act 64 traditional securitization. Entergy Gulf States Louisiana and Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and savings to customers via a Storm Cost Offset rider. On April 3, 2008, the Louisiana State Bond Commission granted preliminary approval for the Act 55 financings. On April 8, 2008, the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuantother parties to the Act 55 financings, approved requests for the Act 55
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
financings. On April 10, 2008, Entergy Gulf States Louisiana and Entergy Louisiana and the LPSC Staffproceeding filed with the LPSC an uncontested stipulated settlement that includes these terms and also includes Entergy Gulf States LouisianaLouisiana’s and Entergy Louisiana's proposals under the Act 55 financings, which includes a commitment to pass on to customers a minimum of $10$15.5 million and $30$27.75 million of customer benefits, respectively, through prospective annual rate reductions of $2$3.1 million and $6$5.55 million for five years. A stipulation hearing was held before the ALJ on April 13, 2010. On April 16, 2008,21, 2010, the LPSC approved the settlement and subsequently issued two financing orders and one ratemaking order intended to facilitate the implementation of the Act 55 financings. In May 2008,June 2010 the Louisiana State Bond Commission granted final approval ofapproved the Act 55 financings.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
OnIn July 29, 2008,2010 the LPFALouisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $687.7$468.9 million in bonds under the aforementioned Act 55. From the $679$462.4 million of bond proceeds loaned by the LPFALCDA to the LURC, the LURC deposited $152$200 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $527$262.4 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana invested $545used $262.4 million including $17.8 million that was withdrawn from the restricted escrow account as approved by the April 16, 2008 LPSC orders, in exchange for 5,449,861.85to acquire 2,624,297.11 Class AB preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 10%9% annual distribution rate. Distributions are payable quarterly commencing on September 15, 20082010, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of Entergy Holdings Company LLC after ten years under the terms of the LLC agreement. The terms of the membership interests include certain financial covenants to which Entergy Holdings Company LLC is subject, including the requirement to maintain a net worth of at least $1 billion.
Entergy Louisiana does not report the bonds on its balance sheet because the bonds are the obligation of the LPFA,LCDA and there is no recourse against Entergy or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy Louisiana does not report the collections as revenue because it is merely acting as the billing and collection agent for the state.
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Louisiana charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Louisiana is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the LPSC, is primarily responsible for approval of the rates charged to customers.
Entergy Louisiana made a rate filing with the LPSC requesting a base rate increase in January 2004. In May 2005 the LPSC approved a rate filing settlement that included the adoption of a three-year formula rate plan, the terms of which included an ROE mid-point of 10.25% for the initial three-year term of the plan and permit Entergy Louisiana to recover incremental capacity costs outside of a traditional base rate proceeding. Under the formula rate plan, over- and under-earnings outside an allowed regulatory range of 9.45% to 11.05% will be allocated 60% to customers and 40% to Entergy Louisiana. The initial formula rate plan filing was made in May 2006. As discussed below the formula rate plan has been extended, with return on common equity provisions consistent with previously approved provisions, to cover the 2008, 2009, 2010, and 20102011 test years.
In October 2009 the LPSC approved a settlement that resolvesresolved Entergy Louisiana'sLouisiana’s 2006 and 2007 test year filings. The settlement providesfilings provided for a new formula rate plan for the 2008, 2009, and 2010 test years. Entergy Louisiana is permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. 10.25% is the target midpoint return on equity for the new formula rate plan, with an earnings bandwidth of +/- 80 basis points (9.45% - 11.05%). Entergy Louisiana was permitted, effective with the November 2009 billing cycle, to reset its rates to achieve a 10.25% return on equity for the 2008 test year. The rate reset, a $2.5 million increase that includesincluded a $16.3 million cost of service adjustment less a $13.8 million net reduction for decreased capacity costs and a base rate reclassification, was implemented for the November 2009 billing cycle, and the rate reset will bewas subject to refund pending review of the 2008 test year filing that was made onin October 21, 2009. The settlement does not allow recovery through the formula rate plan of most of Entergy Louisiana's costs associated with Entergy's stock option plan. Pursuant to the settlementIn April 2010, Entergy Louisiana refunded to its customers $12.9 million, which includes interest, inand the November 2009 billing cycle. The LPSC Staff and one intervenor filed commentsstaff submitted a joint report on the 2008 test year filing and requested that the LPSC accept the report, which resulted in January 2010.a $0.1 million reduction in rates effective in the May 2010 billing cycle and a $0.1 million refund. In addition, Entergy Louisiana has until Marchmoved the recovery of approximately $12.5 million of capacity costs from fuel adjustment clause recovery to base rate recovery. At its April 21, 2010 to provide an initial response tomeeting, the proposed adjustments and discovery is ongoing. Entergy Louisiana will implement any agreed changes by March 15, 2010. A procedural schedule to address any contested issues would be set after March 15, 2010.LPSC accepted the joint report.
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
In December 2009,May 2010, Entergy Louisiana filed an application seekingmade its formula rate plan filing with the LPSC approval for the 2009 test year. The filing reflected a $10.3 million10.82% return on common equity, which is within the allowed earnings bandwidth, indicating no cost of service rate change is necessary under the formula rate plan. The filing does reflect, however, a revenue requirement increase to provide supplemental funding for the decommissioning trust maintained for Waterford 3, in response to ana NRC notification of a projected shortfall of decommissioning funding assurance. Currently, The filing also reflected a rate change for incremental capacity costs. In July 2010 the LPSC approved a $3.5 million increase in the retail revenue requirement for decommissioning, effective September 2010. In August 2010,
Entergy Louisiana, hasLLC and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Louisiana made a revised 2009 test year formula rate plan filing. The revised filing reflected a 10.82% earned return on common equity, which is within the allowed earnings bandwidth resulting in no cost of service adjustment. The filing also reflected two increases outside of the formula rate plan sharing mechanism: (1) the previously approved decommissioning revenue requirement, and (2) $2.2 million for capacity costs. The rates reflected in annual retail rates for decommissioning funding.the revised filing became effective beginning with the first billing cycle of September 2010. Entergy Louisiana and the LPSC staff subsequently submitted a joint report on the 2009 test year filing consistent with these terms and the LPSC approved the joint report in December 2010.
In May 2011, Entergy Louisiana made a special formula rate plan rate implementation filing with the LPSC that implements effective with the May 2011 billing cycle a $43.1 million net rate increase to reflect adjustments in accordance with a previous LPSC order relating to the acquisition of Unit 2 of the Acadia Energy Center. The net rate increase represents the decrease in the additional capacity revenue requirement resulting from the termination of the power purchase agreement with Acadia and the increase in the revenue requirement resulting from the ownership of the Acadia facility. In August 2011, Entergy Louisiana made a filing to correct the May 2011 filing and decrease the rate by $1.1 million.
In May 2008,2011, Entergy Louisiana made its formula rate plan filing with the LPSC for the 20072010 test year, seekingyear. The filing reflects an $18.4 million rate increase, comprised11.07% earned return on common equity, which is just outside of $12.6 million of recovery of incrementalthe allowed earnings bandwidth and deferred capacity costs and $5.8 million based on aresults in no cost of service revenue deficiency related to continued lost contribution to fixed costs associated withrate change under the loss of customers due to Hurricane Katrina. In August 2008,formula rate plan. The filing also reflects a very slight ($9 thousand) rate increase for incremental capacity costs. Entergy Louisiana implementedand the LPSC Staff subsequently filed a $43.9 millionjoint report that reflects an 11.07% earned return and results in no cost of service rate change under the formula rate plan, decrease to remove interim storm cost recovery and to reduce the storm damage accrual. Entergy Louisiana then implemented a $16.9 million formula rate plan increase, subject to refund, effectiveLPSC approved the first billing cyclejoint report in September 2008, comprised of $12.6 million of recovery of incremental and deferred capacity costs and $4.3 million based on a cost of service deficiency.October 2011.
In November 2011 the LPSC approved a one-year extension of Entergy Louisiana’s current formula rate plan. In May 2007,2012, Entergy Louisiana made its formula rate plan filing with the LPSC for the 20062011 test year, indicatingyear. The filing reflected a 7.6%9.63% earned return on common equity. In September 2007, Entergy Louisiana modified its formula rate plan filing to reflect its implementation of certain adjustments proposed by the LPSC Staff in its review of Entergy Louisiana's original filing with which Entergy Louisiana agreed, and to reflect its implementation of an $18.4 million annual formula rate plan increase comprised of (1) a $23.8 million increase representing 60% of Entergy Louisiana's revenue deficiency, and (2) a $5.4 million decrease for reduced incremental and deferred capacity costs. In October 2007, Entergy Louisiana implemented a $7.1 million formula rate plan decrease that was due primarily to the reclassification of certain franchise fees from base rates to collection via a line item on customer bills pursuant to an LPSC Order.
In May 2006, Entergy Louisiana made its formula rate plan filing with the LPSC for the 2005 test year. Entergy Louisiana modified the filing in August 2006 to reflect a 9.45% return on equity, which is within the allowed bandwidth.earnings bandwidth and results in no cost of service rate change under the formula rate plan. The modified filing includesalso reflected an $18.1 million rate increase for incremental capacity costs. In August 2012, Entergy Louisiana submitted a revised filing that reflects an earned return on common equity of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicates that an increase of $24.2$15.9 million for interim recovery of storm costs from Hurricanes Katrina and Rita and a $119.2 millionshould be reflected in the incremental capacity rider. The rate increase to recover LPSC-approved incremental deferred and ongoing capacity costs. The filing requested recovery of approximately $50 million for the amortization of capacity deferrals over a three-year period, including carrying charges, and approximately $70 million for ongoing capacity costs. The increasechange was implemented, subject to refund, effective for bills rendered the first billing cycle of September 2012. The September 2012 rate change contributed approximately $5.3 million to Entergy Louisiana’s revenues in 2012. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflects two items: 1) a $17 million reduction for the first-year capacity charges for the purchase by Entergy Gulf States Louisiana from Entergy Louisiana of one-third of Acadia Unit 2 capacity and energy, and 2) an $88 million increase for the first-year retail revenue requirement associated with the Waterford 3 replacement steam generator project, which was in-service in December 2012. These rate changes were implemented, subject to refund, effective with the first billing cycle of September 2006. Entergy Louisiana subsequently updatedJanuary 2013. The 2011 test year filings remain subject to LPSC review.
In connection with its decision to extend the formula rate plan rider to reflect adjustments proposed bythe 2011 test year, the LPSC Staff with which it agrees. The adjusted return on equity of 9.56% remains within the allowed bandwidth. Ongoing and deferred incremental capacity costs were reduced to $118.7 million. The updated formularequired that a base rate plan rider was implemented, subject to refund, with the first billing cycle of October 2006. An uncontested stipulated settlement wascase be filed in February 2008 that left the current base rates in place,by Entergy Louisiana, and the LPSC approved the settlement in March 2008. In the settlement Entergy Louisiana agreed to credit customers $7.2 million, plus $0.7 million of interest, for customer contributions to the Central States Compact in Nebraska that was never completed and agreed to a one-time $2.6 million deduction from the deferred capacity cost balance. The credit, for which Entergy Louisiana had previously recorded a provision,required filing was made in May 2008.
In additionon February 15, 2013. Recognizing that the final structure of Entergy Louisiana’s transmission business has not been determined, the filing presents two alternative scenarios for the LPSC to rate proceedings,establish the appropriate level of rates for Entergy Louisiana's fuel costs recovered from customers are subject to regulatory scrutiny. This regulatory risk represents Entergy Louisiana's largest potential exposure to price changes in the commodity markets.
Entergy Louisiana's retail rate matters and proceedings, including fuel cost recovery-related issues, are discussed further in Note 2 to the financial statements.Louisiana.
Entergy Louisiana, LLC and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Federal RegulationUnder its primary request, Entergy Louisiana assumes that it has completed integration into MISO and that the spin-off and merger of its transmission business with a subsidiary of ITC Holdings has occurred (the MISO/ITC Scenario). Under the MISO/ITC Scenario, Entergy Louisiana requests:
Interruptible Load Proceeding| · | authorization to increase the revenue it collects from customers by approximately $169 million (which does not take into account a revenue offset of approximately $1 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; |
| · | authorization to implement a transmission cost recovery rider with a forward-looking test year and an annual true-up component; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
SeeUnder the alternative request contained in its filing, Entergy CorporationLouisiana assumes that it has completed integration into MISO, but that the spin-off and Subsidiaries' "merger of its transmission business with a subsidiary of ITC Holdings has not occurred (the MISO-Only Scenario). Under the MISO-Only Scenario, Entergy Louisiana requests:
| · | authorization to increase the revenue it collects from customers by approximately $145 million (which does not take into account a revenue offset of approximately $2 million resulting from a proposed increase for those customers taking service under the Qualifying Facility Standby Service); |
| · | an authorized return on common equity of 10.4%; |
| · | authorization to increase depreciation rates embedded in the proposed revenue requirement; and, |
| · | authorization to implement a three-year formula rate plan with a midpoint return on common equity of 10.4%, plus or minus 75 basis points (the deadband), that would provide a means for the annual re-setting of rates (commencing with calendar year 2013 as its first test year), that would include a mechanism to recover incremental transmission revenue requirement on the basis of a forward-looking test year as compared to the initial base year of 2014 with an annual true-up, that would retain the primary aspects of the prior formula rate plan, including a 60% to customers/40% to Entergy Louisiana sharing mechanism for earnings outside the deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC. |
MANAGEMENT'S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement Proceedings - Interruptible Load Proceeding." In October 2009,April 2010, the LPSC issuedauthorized its staff to initiate an order approving the flow through to retail ratesaudit of Entergy Louisiana's fuel adjustment clause filings. The audit includes a review of the LPSC-jurisdictional portionreasonableness of charges flowed through the paymentsfuel adjustment clause by Entergy Louisiana for the period from 2005 through 2009. The LPSC Staff issued its audit report in January 2013. The LPSC staff recommended that Entergy Louisiana refund approximately $1.9 million, plus interest, to customers and credits resultingrealign the recovery of approximately $1.0 million from Entergy Louisiana's fuel adjustment clause to base rates. Two parties have intervened in the FERC's orders that hadproceeding. A procedural schedule has not yet been flowed through to retail rates, which required a net refund to retail customersestablished. Entergy Louisiana has recorded provisions for the estimated outcome of $17.6 million, including interest. Of this amount, $5.4 million was refunded subject to adjustment in the event that future action by the FERC or the D.C. Circuit Court of Appeals results in a reversal or change in the amount of the refunds ordered by the FERC in September 2008.
System Agreement Proceedings
See "System Agreement Proceedings" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.
Transmission
See "Independent Coordinator of Transmission" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for discussion.proceeding.
Industrial and Commercial Customers
Entergy Louisiana'sLouisiana’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Louisiana'sLouisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service contracts to provide competitive rates that match specific customer needs and load profiles. Entergy Louisiana actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Louisiana does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Louisiana'sLouisiana’s marketing efforts in retaining industrial customers.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Federal Regulation
See “Independent Coordinator of Transmission”, “System Agreement”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of these topics.
Nuclear Matters
Entergy Louisiana owns and, operates, through an affiliate, operates the Waterford 3 nuclear power plant. Entergy Louisiana is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials associated with components within the reactor coolant system. The issue is applicable to Waterford 3 and is managed in accordance with standard industry practices and guidelines. As discussed above in more detail, Entergy Louisiana plans to replacereplaced the Waterford 3 steam generators, along with the reactor vessel closure head and control element drive mechanisms, and placed them in-service in 2011.
Entergy Louisiana, LLC
Management's Financial Discussion and AnalysisDecember 2012.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
Environmental Risks
Entergy Louisiana'sLouisiana’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Louisiana is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Louisiana'sLouisiana’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Louisiana'sLouisiana’s financial position or results of operations.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Nuclear Decommissioning Costs
See "“Nuclear Decommissioning Costs"” in the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In the second quarter 2012, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for Waterford 3 as a result of a revised decommissioning cost study. The revised estimate resulted in a $48.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement obligation asset that will be depreciated over the remaining life of the unit.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Louisiana records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Entergy Louisiana, LLC
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $1,298 | | $13,578 | | (0.25%) | | $2,368 | | $29,843 |
| Rate of return on plan assets | | (0.25%) | | $964 | | - | | (0.25%) | | $1,201 | | $- |
| Rate of increase in compensation | | 0.25% | | $646 | | $3,136 | | 0.25% | | $968 | | $5,869 |
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $897 | | $8,198 |
| Health care cost trend | | 0.25% | | $673 | | $3,576 | | 0.25% | | $1,304 | | $7,321 |
| Discount rate | | (0.25%) | | $387 | | $4,016 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Louisiana in 20092012 was $6.2$37.4 million. Entergy Louisiana anticipates 20102013 qualified pension cost to be $14.6$45.1 million. Entergy Louisiana contributed $7.6$28.8 million to its pension plans in 20092012 and anticipates funding approximately $27.1$20.7 million in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Louisiana’s pension contributions in the future.2013.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 20092012 were $16.8$22.1 million, including $2.8$3.6 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana expects 20102013 postretirement health care and life insurance benefit costs to approximate $17.8$23 million, including $3.1$4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Louisiana expects to contribute approximately $9.9contributed $11 million to its other postretirement plans in 2010.2012 and expects to contribute approximately $10.2 million in 2013.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for a discussion of new accounting pronouncements.Analysis.
To the Board of Directors and Members of
Entergy Louisiana, LLC and Subsidiaries
Baton Rouge, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 20092012 and 20082011 and the related consolidated income statements, consolidated statements of income, members’ equity and comprehensive income, andconsolidated statements of cash flows, and consolidated statements of changes in equity (pages 318335 through 322340 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Louisiana, LLC and Subsidiaries as of December 31, 20092012 and 2008,2011, and the results of itstheir operations and itstheir cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 2,149,443 | | | $ | 2,508,915 | | | $ | 2,538,766 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 360,964 | | | | 596,808 | | | | 667,744 | |
| Purchased power | | | 728,170 | | | | 843,099 | | | | 847,464 | |
| Nuclear refueling outage expenses | | | 24,344 | | | | 27,903 | | | | 24,955 | |
| Other operation and maintenance | | | 449,172 | | | | 470,783 | | | | 432,341 | |
| Decommissioning | | | 23,406 | | | | 24,658 | | | | 22,960 | |
| Taxes other than income taxes | | | 69,186 | | | | 69,769 | | | | 68,687 | |
| Depreciation and amortization | | | 218,140 | | | | 206,986 | | | | 198,133 | |
| Other regulatory charges (credits) - net | | | 127,050 | | | | 182,800 | | | | (20,192 | ) |
| TOTAL | | | 2,000,432 | | | | 2,422,806 | | | | 2,242,092 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 149,011 | | | | 86,109 | | | | 296,674 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 39,610 | | | | 33,033 | | | | 26,875 | |
| Interest and investment income | | | 84,478 | | | | 87,487 | | | | 80,007 | |
| Miscellaneous - net | | | (2,584 | ) | | | (3,520 | ) | | | (4,043 | ) |
| TOTAL | | | 121,504 | | | | 117,000 | | | | 102,839 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 136,967 | | | | 116,803 | | | | 119,484 | |
| Allowance for borrowed funds used during construction | | | (18,611 | ) | | | (17,406 | ) | | | (17,952 | ) |
| TOTAL | | | 118,356 | | | | 99,397 | | | | 101,532 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 152,159 | | | | 103,712 | | | | 297,981 | |
| | | | | | | | | | | | | |
| Income taxes | | | (128,922 | ) | | | (370,211 | ) | | | 66,546 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 281,081 | | | | 473,923 | | | | 231,435 | |
| | | | | | | | | | | | | |
| Preferred distribution requirements and other | | | 6,950 | | | | 6,950 | | | | 6,950 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON EQUITY | | $ | 274,131 | | | $ | 466,973 | | | $ | 224,485 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Net Income | | $ | 281,081 | | | $ | 473,923 | | | $ | 231,435 | |
| Other comprehensive income (loss) | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | | | | | | | | | | | |
| (net of tax expense (benefit) of $5,095, ($7,363), and ($1,818)) | | | (6,625 | ) | | | (14,545 | ) | | | 577 | |
| Other comprehensive income (loss) | | | (6,625 | ) | | | (14,545 | ) | | | 577 | |
| Comprehensive Income | | | 274,456 | | | $ | 459,378 | | | $ | 232,012 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 281,081 | | | $ | 473,923 | | | $ | 231,435 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 293,774 | | | | 288,459 | | | | 285,330 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (59,069 | ) | | | (327,046 | ) | | | 28,896 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 43,850 | | | | (50,014 | ) | | | (6,245 | ) |
| Fuel inventory | | | 336 | | | | (23,916 | ) | | | - | |
| Accounts payable | | | 40,085 | | | | 21,489 | | | | 86,103 | |
| Prepaid taxes and taxes accrued | | | (39,275 | ) | | | 56,348 | | | | (25,993 | ) |
| Interest accrued | | | 729 | | | | 4,646 | | | | (2,991 | ) |
| Deferred fuel costs | | | (93,103 | ) | | | 7,308 | | | | 57,594 | |
| Other working capital accounts | | | (79,771 | ) | | | 34,824 | | | | (51,771 | ) |
| Changes in provisions for estimated losses | | | (16,586 | ) | | | (10,496 | ) | | | 203,255 | |
| Changes in other regulatory assets | | | (116,249 | ) | | | (95,909 | ) | | | 150,952 | |
| Changes in other regulatory liabilities | | | 81,259 | | | | 206,643 | | | | 43,188 | |
| Changes in pension and other postretirement liabilities | | | 80,027 | | | | 114,489 | | | | 49,378 | |
| Other | | | 30,610 | | | | (221,406 | ) | | | (116,797 | ) |
| Net cash flow provided by operating activities | | | 447,698 | | | | 479,342 | | | | 932,334 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (787,075 | ) | | | (433,876 | ) | | | (428,373 | ) |
| Allowance for equity funds used during construction | | | 39,610 | | | | 33,033 | | | | 26,875 | |
| Insurance proceeds | | | - | | | | - | | | | 188 | |
| Nuclear fuel purchases | | | (159,501 | ) | | | (155,932 | ) | | | (617 | ) |
| Proceeds from the sale of nuclear fuel | | | 62,248 | | | | 11,570 | | | | - | |
| Payment for purchase of plant | | | - | | | | (299,589 | ) | | | - | |
| Investment in affiliates | | | - | | | | - | | | | (262,430 | ) |
| Payments to storm reserve escrow account | | | - | | | | - | | | | (200,166 | ) |
| Receipts from storm reserve escrow account | | | 13,669 | | | | - | | | | - | |
| Remittances to transition charge account | | | (30,042 | ) | | | (5,200 | ) | | | - | |
| Payments from transition charge account | | | 30,860 | | | | - | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 27,577 | | | | 19,909 | | | | 44,500 | |
| Investment in nuclear decommissioning trust funds | | | (39,374 | ) | | | (30,728 | ) | | | (53,579 | ) |
| Change in money pool receivable - net | | | (9,433 | ) | | | 49,887 | | | | 2,920 | |
| Changes in other investments - net | | | - | | | | - | | | | 9,353 | |
| Other | | | 595 | | | | (277 | ) | | | - | |
| Net cash flow used in investing activities | | | (850,866 | ) | | | (811,203 | ) | | | (861,329 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 663,975 | | | | 1,170,441 | | | | 498,801 | |
| Retirement of long-term debt | | | (50,899 | ) | | | (785,547 | ) | | | (567,326 | ) |
| Change in money pool payable - net | | | (118,415 | ) | | | 118,415 | | | | - | |
| Changes in credit borrowings - net | | | (39,735 | ) | | | 71,326 | | | | (24,125 | ) |
| Dividends/distributions paid: | | | | | | | | | | | | |
| Common equity | | | (15,600 | ) | | | (358,200 | ) | | | - | |
| Preferred membership interests | | | (6,950 | ) | | | (6,950 | ) | | | (6,950 | ) |
| Net cash flow provided by (used in) financing activities | | | 432,376 | | | | 209,485 | | | | (99,600 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 29,208 | | | | (122,376 | ) | | | (28,595 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 878 | | | | 123,254 | | | | 151,849 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 30,086 | | | $ | 878 | | | $ | 123,254 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 130,934 | | | $ | 108,072 | | | $ | 118,676 | |
| Income taxes | | $ | (41,423 | ) | | $ | (39,555 | ) | | $ | 28,266 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 2,183,586 | | | $ | 3,051,294 | | | $ | 2,737,552 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 428,904 | | | | 1,048,502 | | | | 887,749 | |
| Purchased power | | | 782,235 | | | | 1,010,804 | | | | 814,779 | |
| Nuclear refueling outage expenses | | | 21,895 | | | | 19,638 | | | | 17,664 | |
| Other operation and maintenance | | | 401,898 | | | | 408,489 | | | | 427,241 | |
| Decommissioning | | | 21,377 | | | | 19,907 | | | | 18,530 | |
| Taxes other than income taxes | | | 66,627 | | | | 63,184 | | | | 60,293 | |
| Depreciation and amortization | | | 203,791 | | | | 197,909 | | | | 178,841 | |
| Other regulatory charges (credits) - net | | | (7,561 | ) | | | 32,763 | | | | 43,949 | |
| TOTAL | | | 1,919,166 | | | | 2,801,196 | | | | 2,449,046 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 264,420 | | | | 250,098 | | | | 288,506 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 27,990 | | | | 18,439 | | | | 11,119 | |
| Interest and dividend income | | | 75,522 | | | | 46,370 | | | | 8,901 | |
| Miscellaneous - net | | | (4,425 | ) | | | (3,703 | ) | | | (3,497 | ) |
| TOTAL | | | 99,087 | | | | 61,106 | | | | 16,523 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 96,353 | | | | 83,003 | | | | 74,021 | |
| Other interest - net | | | 7,318 | | | | 11,307 | | | | 11,708 | |
| Allowance for borrowed funds used during construction | | | (18,059 | ) | | | (11,297 | ) | | | (7,531 | ) |
| TOTAL | | | 85,612 | | | | 83,013 | | | | 78,198 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 277,895 | | | | 228,191 | | | | 226,831 | |
| | | | | | | | | | | | | |
| Income taxes | | | 45,050 | | | | 70,648 | | | | 83,494 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 232,845 | | | | 157,543 | | | | 143,337 | |
| | | | | | | | | | | | | |
| Preferred distribution requirements and other | | | 6,950 | | | | 6,950 | | | | 6,950 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON EQUITY | | $ | 225,895 | | | $ | 150,593 | | | $ | 136,387 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 814 | | | $ | 878 | |
| Temporary cash investments | | | 29,272 | | | | - | |
| Total cash and cash equivalents | | | 30,086 | | | | 878 | |
| Securitization recovery trust account | | | 4,382 | | | | 5,200 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 86,072 | | | | 102,379 | |
| Allowance for doubtful accounts | | | (867 | ) | | | (1,147 | ) |
| Associated companies | | | 42,938 | | | | 60,661 | |
| Other | | | 9,354 | | | | 10,945 | |
| Accrued unbilled revenues | | | 79,354 | | | | 78,430 | |
| Total accounts receivable | | | 216,851 | | | | 251,268 | |
| Accumulated deferred income taxes | | | 113,319 | | | | - | |
| Deferred fuel costs | | | 26,568 | | | | - | |
| Fuel inventory | | | 23,583 | | | | 23,919 | |
| Materials and supplies - at average cost | | | 152,170 | | | | 140,561 | |
| Deferred nuclear refueling outage costs | | | 44,457 | | | | 24,197 | |
| Prepaid taxes | | | 7,937 | | | | - | |
| Prepayments and other | | | 12,129 | | | | 13,171 | |
| TOTAL | | | 631,482 | | | | 459,194 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliate preferred membership interests | | | 807,423 | | | | 807,424 | |
| Decommissioning trust funds | | | 287,418 | | | | 253,968 | |
| Storm reserve escrow account | | | 186,985 | | | | 201,249 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 578 | | | | 760 | |
| TOTAL | | | 1,282,404 | | | | 1,263,401 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 8,603,319 | | | | 7,859,136 | |
| Property under capital lease | | | 324,440 | | | | 274,334 | |
| Construction work in progress | | | 404,714 | | | | 559,437 | |
| Nuclear fuel | | | 204,019 | | | | 165,380 | |
| TOTAL UTILITY PLANT | | | 9,536,492 | | | | 8,858,287 | |
| Less - accumulated depreciation and amortization | | | 3,590,146 | | | | 3,606,706 | |
| UTILITY PLANT - NET | | | 5,946,346 | | | | 5,251,581 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 193,114 | | | | 175,952 | |
| Other regulatory assets (includes securitization property of | | | | | | | | |
| $172,838 as of December 31, 2012 and | | | | | | | | |
| $198,445 as of December 31, 2011) | | | 913,562 | | | | 814,472 | |
| Deferred fuel costs | | | 67,998 | | | | 67,998 | |
| Other | | | 39,178 | | | | 31,269 | |
| TOTAL | | | 1,213,852 | | | | 1,089,691 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 9,074,084 | | | $ | 8,063,867 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 14,236 | | | $ | 75,309 | |
| Short-term borrowings | | | 54,657 | | | | 44,392 | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 103,454 | | | | 218,001 | |
| Other | | | 266,904 | | | | 130,295 | |
| Customer deposits | | | 88,805 | | | | 86,099 | |
| Accumulated deferred income taxes | | | - | | | | 4,690 | |
| Taxes accrued | | | - | | | | 31,338 | |
| Interest accrued | | | 37,264 | | | | 36,535 | |
| Deferred fuel costs | | | - | | | | 66,535 | |
| Pension and other postretirement liabilities | | | 9,170 | | | | 9,161 | |
| System agreement cost equalization | | | - | | | | 36,800 | |
| Gas hedge contracts | | | 3,442 | | | | 12,397 | |
| Other | | | 13,382 | | | | 19,278 | |
| TOTAL | | | 591,314 | | | | 770,830 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 930,606 | | | | 1,098,690 | |
| Accumulated deferred investment tax credits | | | 70,193 | | | | 73,283 | |
| Other regulatory liabilities | | | 376,801 | | | | 295,542 | |
| Decommissioning | | | 418,122 | | | | 345,834 | |
| Accumulated provisions | | | 196,474 | | | | 213,060 | |
| Pension and other postretirement liabilities | | | 539,703 | | | | 459,685 | |
| Long-term debt (includes securitization bonds of | | | | | | | | |
| $181,553 as of December 31, 2012 and | | | | | | | | |
| $207,123 as of December 31, 2011) | | | 2,811,859 | | | | 2,177,003 | |
| Other | | | 68,516 | | | | 65,011 | |
| TOTAL | | | 5,412,274 | | | | 4,728,108 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| EQUITY | | | | | | | | |
| Preferred membership interests without sinking fund | | | 100,000 | | | | 100,000 | |
| Member's equity | | | 3,016,628 | | | | 2,504,436 | |
| Accumulated other comprehensive loss | | | (46,132 | ) | | | (39,507 | ) |
| TOTAL | | | 3,070,496 | | | | 2,564,929 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 9,074,084 | | | $ | 8,063,867 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | | | | Common Equity | | | | |
| | | Preferred Membership Interests | | | Member's Equity | | | Accumulated Other Comprehensive Income (Loss) | | | Total | |
| | | (In Thousands) | | | | | | | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 100,000 | | | $ | 1,837,348 | | | $ | (25,539 | ) | | $ | 1,911,809 | |
| Net income | | | - | | | | 231,435 | | | | - | | | | 231,435 | |
| Other comprehensive income | | | - | | | | - | | | | 577 | | | | 577 | |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (6,950 | ) | | | - | | | | (6,950 | ) |
| Balance at December 31, 2010 | | $ | 100,000 | | | $ | 2,061,833 | | | $ | (24,962 | ) | | $ | 2,136,871 | |
| Net income | | | - | | | | 473,923 | | | | - | | | | 473,923 | |
| Additional contribution from parent | | | - | | | | 333,830 | | | | - | | | | 333,830 | |
| Other comprehensive loss | | | - | | | | - | | | | (14,545 | ) | | | (14,545 | ) |
| Dividends/distributions declared on common equity | | | - | | | | (358,200 | ) | | | - | | | | (358,200 | ) |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (6,950 | ) | | | - | | | | (6,950 | ) |
| Balance at December 31, 2011 | | $ | 100,000 | | | $ | 2,504,436 | | | $ | (39,507 | ) | | $ | 2,564,929 | |
| Net income | | | - | | | | 281,081 | | | | - | | | | 281,081 | |
| Additional contribution from parent | | | - | | | | 253,661 | | | | - | | | | 253,661 | |
| Other comprehensive income | | | - | | | | - | | | | (6,625 | ) | | | (6,625 | ) |
| Dividends/distributions declared on common equity | | | - | | | | (15,600 | ) | | | - | | | | (15,600 | ) |
| Dividends/distributions declared on preferred membership interests | | | - | | | | (6,950 | ) | | | - | | | | (6,950 | ) |
| Balance at December 31, 2012 | | $ | 100,000 | | | $ | 3,016,628 | | | $ | (46,132 | ) | | $ | 3,070,496 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 2,149,443 | | | $ | 2,508,915 | | | $ | 2,538,766 | | | $ | 2,183,586 | | | $ | 3,051,294 | |
| Net Income | | $ | 281,081 | | | $ | 473,923 | | | $ | 231,435 | | | $ | 232,845 | | | $ | 157,543 | |
| Total assets | | $ | 9,074,084 | | | $ | 8,063,867 | | | $ | 7,488,423 | | | $ | 6,861,903 | | | $ | 6,685,168 | |
| Long-term obligations (1) | | $ | 2,811,859 | | | $ | 2,177,003 | | | $ | 1,771,566 | | | $ | 1,622,709 | | | $ | 1,423,316 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 687 | | | $ | 830 | | | $ | 840 | | | $ | 669 | | | $ | 967 | |
| Commercial | | | 482 | | | | 549 | | | | 543 | | | | 456 | | | | 660 | |
| Industrial | | | 731 | | | | 867 | | | | 817 | | | | 664 | | | | 1,062 | |
| Governmental | | | 38 | | | | 42 | | | | 42 | | | | 36 | | | | 51 | |
| Total retail | | $ | 1,938 | | | $ | 2,288 | | | $ | 2,242 | | | $ | 1,825 | | | | 2,740 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 137 | | | | 137 | | | | 220 | | | | 252 | | | | 249 | |
| Non-associated companies | | | 2 | | | | 8 | | | | 5 | | | | 5 | | | | 12 | |
| Other | | | 72 | | | | 76 | | | | 72 | | | | 102 | | | | 50 | |
| Total | | $ | 2,149 | | | $ | 2,509 | | | $ | 2,539 | | | $ | 2,184 | | | $ | 3,051 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 8,703 | | | | 9,303 | | | | 9,533 | | | | 8,684 | | | | 8,487 | |
| Commercial | | | 6,112 | | | | 6,155 | | | | 6,164 | | | | 5,867 | | | | 5,784 | |
| Industrial | | | 16,416 | | | | 15,813 | | | | 14,473 | | | | 13,386 | | | | 13,162 | |
| Governmental | | | 479 | | | | 473 | | | | 479 | | | | 459 | | | | 459 | |
| Total retail | | | 31,710 | | | | 31,744 | | | | 30,649 | | | | 28,396 | | | | 27,892 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 2,156 | | | | 2,145 | | | | 2,860 | | | | 1,513 | | | | 2,028 | |
| Non-associated companies | | | 65 | | | | 185 | | | | 101 | | | | 109 | | | | 205 | |
| Total | | | 33,931 | | | | 34,074 | | | | 33,610 | | | | 30,018 | | | | 30,125 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 232,845 | | | $ | 157,543 | | | $ | 143,337 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Other regulatory charges (credits) - net | | | (7,561 | ) | | | 32,763 | | | | 43,949 | |
| Depreciation, amortization, and decommissioning | | | 225,168 | | | | 217,816 | | | | 197,371 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | (183,872 | ) | | | 123,219 | | | | (26,634 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 193,181 | | | | (111,579 | ) | | | (65,082 | ) |
| Accounts payable | | | (25,074 | ) | | | 9,344 | | | | (74,923 | ) |
| Taxes accrued | | | 300 | | | | 17,937 | | | | 1,519 | |
| Interest accrued | | | (5,325 | ) | | | 8,541 | | | | (750 | ) |
| Deferred fuel costs | | | (89,930 | ) | | | 42,779 | | | | 95,094 | |
| Other working capital accounts | | | (168,238 | ) | | | 116,565 | | | | 46,418 | |
| Provision for estimated losses and reserves | | | 1,455 | | | | 1,511 | | | | (5,393 | ) |
| Changes in other regulatory assets | | | (84,503 | ) | | | 412,561 | | | | (23,829 | ) |
| Changes in pension and other postretirement liabilities | | | 13,664 | | | | 136,897 | | | | (860 | ) |
| Other | | | (14,231 | ) | | | (83,305 | ) | | | 23,221 | |
| Net cash flow provided by operating activities | | | 87,879 | | | | 1,082,592 | | | | 353,438 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (467,519 | ) | | | (584,394 | ) | | | (321,506 | ) |
| Allowance for equity funds used during construction | | | 27,990 | | | | 18,439 | | | | 11,119 | |
| Insurance proceeds | | | 153 | | | | 11,317 | | | | 10,065 | |
| Nuclear fuel purchases | | | (93,272 | ) | | | (71,328 | ) | | | (3,131 | ) |
| Proceeds from the sale/leaseback of nuclear fuel | | | 93,672 | | | | 70,928 | | | | 14,306 | |
| Investment in affiliates | | | 160 | | | | (545,154 | ) | | | - | |
| Payments to storm reserve escrow account | | | - | | | | (134,423 | ) | | | - | |
| Receipts from storm reserve escrow account | | | - | | | | 133,622 | | | | - | |
| Proceeds from nuclear decommissioning trust fund sales | | | 47,520 | | | | 23,497 | | | | 23,848 | |
| Investment in nuclear decommissioning trust funds | | | (54,379 | ) | | | (31,262 | ) | | | (32,161 | ) |
| Change in money pool receivable - net | | | 8,429 | | | | (61,236 | ) | | | - | |
| Changes in other investments - net | | | 995 | | | | (1,000 | ) | | | - | |
| Net cash flow used in investing activities | | | (436,251 | ) | | | (1,170,994 | ) | | | (297,460 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 395,450 | | | | 296,761 | | | | - | |
| Additional equity from parent | | | - | | | | - | | | | 1,119 | |
| Retirement of long-term debt | | | (6,597 | ) | | | (60,000 | ) | | | - | |
| Change in money pool payable - net | | | - | | | | (2,791 | ) | | | (51,250 | ) |
| Dividends/distributions paid: | | | | | | | | | | | | |
| Common equity | | | (20,600 | ) | | | - | | | | - | |
| Preferred membership interests | | | (6,950 | ) | | | (6,950 | ) | | | (8,069 | ) |
| Other | | | - | | | | - | | | | (221 | ) |
| Net cash flow provided by (used in) financing activities | | | 361,303 | | | | 227,020 | | | | (58,421 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 12,931 | | | | 138,618 | | | | (2,443 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 138,918 | | | | 300 | | | | 2,743 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 151,849 | | | $ | 138,918 | | | $ | 300 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid/(received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 105,586 | | | $ | 82,449 | | | $ | 82,584 | |
| Income taxes | | $ | 223,610 | | | $ | (12,718 | ) | | $ | 119,080 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 160 | | | $ | - | |
| Temporary cash investments | | | 151,689 | | | | 138,918 | |
| Total cash and cash equivalents | | | 151,849 | | | | 138,918 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 56,978 | | | | 127,765 | |
| Allowance for doubtful accounts | | | (1,312 | ) | | | (1,698 | ) |
| Associated companies | | | 110,425 | | | | 244,575 | |
| Other | | | 9,174 | | | | 11,271 | |
| Accrued unbilled revenues | | | 72,550 | | | | 67,512 | |
| Total accounts receivable | | | 247,815 | | | | 449,425 | |
| Note receivable - Entergy New Orleans | | | 9,353 | | | | - | |
| Accumulated deferred income taxes | | | - | | | | 66,229 | |
| Materials and supplies - at average cost | | | 127,812 | | | | 128,388 | |
| Deferred nuclear refueling outage costs | | | 36,783 | | | | 19,962 | |
| Gas hedge contracts | | | 3,409 | | | | - | |
| Prepayments and other | | | 10,633 | | | | 10,046 | |
| TOTAL | | | 587,654 | | | | 812,968 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliate preferred membership interests | | | 544,994 | | | | 545,154 | |
| Decommissioning trust funds | | | 209,070 | | | | 180,862 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 1,124 | | | | 1,306 | |
| Note receivable - Entergy New Orleans | | | - | | | | 9,353 | |
| Other | | | 810 | | | | 1,805 | |
| TOTAL | | | 755,998 | | | | 738,480 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 7,190,609 | | | | 6,734,732 | |
| Property under capital lease | | | 262,111 | | | | 256,348 | |
| Construction work in progress | | | 509,667 | | | | 602,070 | |
| Nuclear fuel under capital lease | | | 122,011 | | | | 74,197 | |
| TOTAL UTILITY PLANT | | | 8,084,398 | | | | 7,667,347 | |
| Less - accumulated depreciation and amortization | | | 3,370,225 | | | | 3,245,701 | |
| UTILITY PLANT - NET | | | 4,714,173 | | | | 4,421,646 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 132,086 | | | | 107,596 | |
| Other regulatory assets | | | 477,020 | | | | 515,053 | |
| Deferred fuel costs | | | 67,998 | | | | 67,998 | |
| Long-term receivables | | | 1,500 | | | | 1,209 | |
| Other | | | 18,762 | | | | 20,218 | |
| TOTAL | | | 697,366 | | | | 712,074 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 6,755,191 | | | $ | 6,685,168 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| BALANCE SHEETS | |
| LIABILITIES AND MEMBERS' EQUITY | |
| | | | | | | | | |
| | | December 31, | |
| | | | 2009 | | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | | $ | 222,326 | | | $ | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 56,057 | | | | 67,465 | |
| Other | | | 141,311 | | | | 254,055 | |
| Customer deposits | | | 82,864 | | | | 78,401 | |
| Taxes accrued | | | 25,993 | | | | 25,693 | |
| Accumulated deferred income taxes | | | 13,349 | | | | - | |
| Interest accrued | | | 32,955 | | | | 38,280 | |
| Deferred fuel costs | | | 1,633 | | | | 91,563 | |
| Obligations under capital leases | | | 56,528 | | | | 38,362 | |
| Pension and other postretirement liabilities | | | 9,153 | | | | 8,935 | |
| System agreement cost equalization | | | 54,000 | | | | 156,000 | |
| Gas hedge contracts | | | - | | | | 26,668 | |
| Other | | | 9,831 | | | | 33,841 | |
| TOTAL | | | 706,000 | | | | 819,263 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 1,703,272 | | | | 1,940,065 | |
| Accumulated deferred investment tax credits | | | 79,650 | | | | 82,848 | |
| Obligations under capital leases | | | 65,483 | | | | 35,843 | |
| Other regulatory liabilities | | | 45,711 | | | | 43,562 | |
| Decommissioning | | | 298,216 | | | | 276,839 | |
| Accumulated provisions | | | 20,301 | | | | 19,916 | |
| Pension and other postretirement liabilities | | | 296,347 | | | | 282,683 | |
| Long-term debt | | | 1,557,226 | | | | 1,387,473 | |
| Other | | | 71,176 | | | | 88,838 | |
| TOTAL | | | 4,137,382 | | | | 4,158,067 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| MEMBERS' EQUITY | | | | | | | | |
| Preferred membership interests without sinking fund | | | 100,000 | | | | 100,000 | |
| Members' equity | | | 1,837,348 | | | | 1,632,053 | |
| Accumulated other comprehensive loss | | | (25,539 | ) | | | (24,215 | ) |
| TOTAL | | | 1,911,809 | | | | 1,707,838 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND MEMBERS' EQUITY | | $ | 6,755,191 | | | $ | 6,685,168 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| STATEMENTS OF MEMBERS' EQUITY AND COMPREHENSIVE INCOME | |
| | | | | | | | | | | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | |
| MEMBERS' EQUITY | | | | | | | | | | | | | | | | | | |
| Members' Equity, January 1 | | $ | 1,632,053 | | | | | | $ | 1,481,509 | | | | | | $ | 1,344,003 | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | | | | | | | | | | |
| Net income | | | 232,845 | | | $ | 232,845 | | | | 157,543 | | | $ | 157,543 | | | | 143,337 | | | $ | 143,337 | |
| Additional equity from parent | | | - | | | | | | | | - | | | | | | | | 1,119 | | | | | |
| Total | | | 232,845 | | | | | | | | 157,543 | | | | | | | | 144,456 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | | | | | | | | | | | | | |
| Dividends/distribution declared: | | | | | | | | | | | | | | | | | | | | | | | | |
| Common equity | | | 20,600 | | | | | | | | - | | | | | | | | - | | | | | |
| Preferred membership interests | | | 6,950 | | | | 6,950 | | | | 6,950 | | | | 6,950 | | | | 6,950 | | | | 6,950 | |
| Other | | | - | | | | | | | | 49 | | | | | | | | - | | | | | |
| Total | | | 27,550 | | | | | | | | 6,999 | | | | | | | | 6,950 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Members' Equity, December 31 | | $ | 1,837,348 | | | | | | | $ | 1,632,053 | | | | | | | $ | 1,481,509 | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| ACCUMULATED OTHER COMPREHENSIVE | | | | | | | | | | | | | | | | | | | | | | |
| INCOME (Net of Taxes): | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Accumulated other comprehensive income | | $ | (24,215 | ) | | | | | | $ | (27,968 | ) | | | | | | $ | (25,695 | ) | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities (net of tax expense (benefit) | | | | | | | | | | | | | | | | | |
| of ($1,692), $2,835, and ($6,703)) | | | (1,324 | ) | | | (1,324 | ) | | | 3,753 | | | | 3,753 | | | | (2,273 | ) | | | (2,273 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at end of period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Pension and other postretirement liabilities | | $ | (25,539 | ) | | | | | | $ | (24,215 | ) | | | | | | $ | (27,968 | ) | | | | |
| Comprehensive Income | | | | | | $ | 224,571 | | | | | | | $ | 154,346 | | | | | | | $ | 134,114 | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (In Thousands) |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 2,183,586 | | | $ | 3,051,294 | | | $ | 2,737,552 | | | $ | 2,451,258 | | | $ | 2,650,181 | |
| Net Income | | $ | 232,845 | | | $ | 157,543 | | | $ | 143,337 | | | $ | 137,618 | | | $ | 128,082 | |
| Total assets | | $ | 6,775,191 | | | $ | 6,685,168 | | | $ | 5,723,121 | | | $ | 5,654,842 | | | $ | 5,855,053 | |
| Long-term obligations (1) | | $ | 1,622,709 | | | $ | 1,423,316 | | | $ | 1,149,478 | | | $ | 1,191,044 | | | $ | 1,208,140 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | |
| | | (Dollars In Millions) |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 669 | | | $ | 967 | | | $ | 854 | | | $ | 797 | | | $ | 828 | |
| Commercial | | | 456 | | | | 660 | | | | 578 | | | | 533 | | | | 539 | |
| Industrial | | | 664 | | | | 1,062 | | | | 872 | | | | 809 | | | | 834 | |
| Governmental | | | 36 | | | | 51 | | | | 43 | | | | 40 | | | | 41 | |
| Total retail | | | 1,825 | | | | 2,740 | | | | 2,347 | | | | 2,179 | | | | 2,242 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 252 | | | | 249 | | | | 310 | | | | 215 | | | | 339 | |
| Non-associated companies | | | 5 | | | | 12 | | | | 8 | | | | 12 | | | | 14 | |
| Other | | | 102 | | | | 50 | | | | 73 | | | | 45 | | | | 55 | |
| Total | | $ | 2,184 | | | $ | 3,051 | | | $ | 2,738 | | | $ | 2,451 | | | $ | 2,650 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 8,684 | | | | 8,487 | | | | 8,646 | | | | 8,558 | | | | 8,559 | |
| Commercial | | | 5,867 | | | | 5,784 | | | | 5,848 | | | | 5,714 | | | | 5,554 | |
| Industrial | | | 13,386 | | | | 13,162 | | | | 13,209 | | | | 12,770 | | | | 12,348 | |
| Governmental | | | 459 | | | | 459 | | | | 446 | | | | 441 | | | | 428 | |
| Total retail (2) | | | 28,396 | | | | 27,892 | | | | 28,149 | | | | 27,483 | | | | 26,889 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 1,513 | | | | 2,028 | | | | 2,299 | | | | 2,369 | | | | 2,451 | |
| Non-associated companies | | | 109 | | | | 205 | | | | 112 | | | | 101 | | | | 109 | |
| Total | | | 30,018 | | | | 30,125 | | | | 30,560 | | | | 29,953 | | | | 29,449 | |
| | | | | | | | | | | | | | | | | | | | | |
| (2) 2006 billed electric energy sales includes 96 GWh of billings related to 2005 deliveries that were billed in 2006 because of billing delays following Hurricane Katrina, which results in an increase of 402 GWh in 2006, or 1.5% and an increase of 762 in 2007, or 2.8%. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
ENTERGY MISSISSIPPI, INC.
Plan to Spin Off the Utility’s Transmission Business
See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt and preferred securities.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy Mississippi’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy Mississippi’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $22 million. Entergy Mississippi recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy Mississippi recorded corresponding regulatory assets of approximately $7 million and construction work in progress of approximately $15 million. Entergy Mississippi recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy Mississippi has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy Mississippi is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Results of Operations
Net Income
20092012 Compared to 20082011
Net income decreased $62.0 million primarily due to a higher effective income tax rate and higher other operation and maintenance expenses.
2011 Compared to 2010
Net income increased $17.9$23.4 million primarily due to higher net revenue, partially offset by higher interest expense and higher depreciation and amortization expenses.a lower effective income tax rate.
2008 Compared to 2007
Net income decreased $12.4 million primarily due to higher other operation and maintenance expenses, lower other income, and higher depreciation and amortization expenses, partially offset by higher net revenue.
Net Revenue
20092012 Compared to 20082011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges (credits). Following is an analysis of the change in net revenue comparing 20092012 to 2008.2011.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $498.8 |
Retail electric price | | 18.9 |
Net wholesale revenue | | 7.6 |
Reserve equalization | | 5.9 |
Other | | 2.7 |
2009 net revenue | | $533.9 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 554.9 | |
| Retail electric price | | | 28.3 | |
| Volume/weather | | | (4.4 | ) |
| Other | | | (0.8 | ) |
| 2012 net revenue | | $ | 578.0 | |
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
The retail electric price variance is primarily due to a formula rate plan increase effective July 2009 and an increase in Attala power plantthe storm cost recovery rider, as approved by the MPSC for a five-month period effective August 2012. The recovery of storm costs that are recovered through the power management rider. The formula rate plan filing is discussed further in "State and Local Rate Regulation" below. The net income effect of the Attala power plant costs recovery is limited to a portion representing an allowed return on equity with the remainder offset by Attala power plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes.expenses.
The net wholesale revenuevolume/weather variance is primarily due to a changedecrease of 301 GWh, or 2%, in a contract with a wholesale customer that increased its monthly demand charge and an increased net balance on joint account sales as a resultbilled electricity usage, including the effect of lower fuel prices in 2009.
The reserve equalization variance is primarily due to increased reserve equalization revenue as a result of changes in the Entergy System generation mixmilder weather compared to the same period in 2008.last year on residential and commercial sales.
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges (credits)
Gross operating revenues decreased primarily due to a decrease of $254.6$84.1 million in gross wholesale revenues due to a decrease in sales to affiliated customers and a decrease of $89.5 million in fuel cost recovery revenues dueprimarily attributable to lower fuel rates and decreased usage and arates. The decrease of $52.1 million in gross wholesale revenues
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
primarily due to a decrease in volume as a result of less energy available for resale sales,was partially offset by an increase of $20.4$20.7 million in power managementstorm cost recovery rider revenue.revenue, as discussed above. Entergy Mississippi’s fuel recovery mechanism and storm cost recovery rider are discussed further in Note 2 to the financial statements.
Fuel and purchased power expenses decreased primarily due to decreasesa decrease in the average market prices of natural gas and purchased power.power and a decrease in deferred fuel expense due to the timing of receipt of System Agreement payments and credits to customers. See Note 2 to the financial statements for a discussion of the System Agreement proceedings.
Other regulatory charges (credits) decreased primarily due to decreased recovery of costs associated with the power management recovery rider and decreased recovery through the Grand Gulf Rider of Grand Gulf capacity costs due to lower rates and decreased usage.rider. There is no material effect on net income due to quarterly adjustments tobecause the power management recovery rider and annual adjustments to the Grand Gulf rider. See Note 2 to the financial statements for additional information regarding the power managementis an exact recovery rider and the Grand Gulf Rider.any differences in revenues and expenses are deferred for future recovery.
20082011 Compared to 20072010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20082011 to 2007.2010.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $486.9 |
Attala costs | | 9.9 |
Rider revenue | | 6.0 |
Base revenue | | 5.1 |
Reserve equalization | | (2.4) |
Net wholesale revenue | | (4.0) |
Other | | (2.7) |
2008 net revenue | | $498.8 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 555.3 | |
| Volume/weather | | | (4.5 | ) |
| Transmission equalization | | | 4.5 | |
| Other | | | (0.4 | ) |
| 2011 net revenue | | $ | 554.9 | |
The Attala costs variance is primarily due to an increase in the Attala power plant costs that are recovered through the power management rider. The net income effect of this recovery in limited to a portion representing an allowed return on equity with the remainder offset by Attala power plant costs in other operation and maintenance expenses, depreciation expenses, and taxes other than income taxes.
The rider revenue variance is the result of a storm damage rider that became effective in October 2007. The establishment of this rider results in an increase in rider revenue and a corresponding increase in other operation and maintenance expense for the storm reserve with no effect on net income.
The base revenuevolume/weather variance is primarily due to a formula rate plan increase effective July 2007. The formula rate plan filing is discussed furtherdecrease of 97 GWh in "Stateweather-adjusted usage in the residential and Local Rate Regulation" below.commercial sectors and a decrease in sales volume in the unbilled sales period.
The reservetransmission equalization variance is primarily due to changesthe addition in the Entergy System generation mix compared2011 of transmission investments that are subject to the same period in 2007.
The net wholesale revenue variance is primarily due to lower profit on joint account sales and reduced capacity revenue from the Municipal Energy Agency of Mississippi.equalization.
Gross operating revenues and fuel and purchased power expenses and other regulatory charges
Gross operating revenues increased primarily due to an increase of $152.5$57.5 million in gross wholesale revenues due to an increase in sales to affiliated customers, partially offset by a decrease of $26.9 million in power management rider revenue.
Fuel and purchased power expenses increased primarily due to an increase in deferred fuel cost recoveryexpense as a result of higher fuel revenues due to higher fuel rates, partially offset by a decrease of $43 million in gross wholesale revenues due to a decrease in net generation and purchases in excess of decreased net area demand resulting in less energy available for resale sales coupled with a decrease in system agreement remedy receipts.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
Fuel and purchased power expenses increased primarily due to increases in the average market prices of natural gas and purchased power, partially offset by decreased demandpower.
Entergy Mississippi, Inc.
Management’s Financial Discussion and decreased recovery from customers of deferred fuel costs.Analysis
Other regulatory charges increased primarily due to increased recovery through the Grand Gulf rider of Grand Gulf capacity costs due to higher rates and increased recovery of costs associated with the power management recovery rider. There is no material effect on net income due to quarterly adjustments to the power management recovery rider. See Note 2 to the financial statements for additional information regarding the power management recovery rider and the Grand Gulf Rider.
Other Income Statement Variances
20092012 Compared to 20082011
Other operation and maintenance expenses increased primarily due to:
| · | an increase of $21.1 million resulting from a temporary increase in the storm damage reserve authorized by the MPSC effective August 2012; |
| · | $7.6 million of costs incurred in 2012 related to the planned spin-off and merger of the transmission business; and |
| · | an increase of $4.8 million in compensation and benefits costs primarily resulting from decreasing discount rates and changes in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs. |
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes due to a higher 2012 assessment as compared to 2011.
Depreciation and amortization expenses increased primarily due to an increase in plant in service.
Other income increaseddecreased primarily due to the gain recordeda decrease in 2009 on the sale of utility property, offset by a potential buyer's forfeiture of a $1.7 million depositallowance for equity funds used during construction due to less construction work in June 2008 for an optionprogress in 2012 as compared to purchase non-utility property.2011.
Interest expense increased primarily due to a revision in 2011 caused by FERC’s acceptance of a change in the issuancetreatment of $150 million of 6.64% Series first mortgage bonds in June 2009.funds received from independent power producers for transmission interconnection projects.
20082011 Compared to 20072010
Other operation and maintenance expenses increaseddecreased primarily due to:
| · | a $5.4 million decrease in compensation and benefits costs primarily resulting from an increase of $8.6 million in loss reservesthe accrual for incentive-based compensation in 2008 compared to 2007, including the effect of the storm damage rider implemented2010 and a decrease in October 2007; |
· | an increase of $3.5 million in fossil plant expenses due to increased outages, higher plant maintenance costs, and environmental costs; |
· | an increase of $2.8 million in distribution expenses due primarily to the timing of contract work and lower reimbursements;stock option expense; and |
| · | an increasethe sale of $1.4$4.9 million in legal spending due to increased regulatory activity.of surplus oil inventory. |
The increasedecrease was partially offset by a decreasean increase of $5.9$3.9 million in payroll, payroll-related, and benefit costs.legal expenses due to the deferral in 2010 of certain litigation expenses in accordance with regulatory treatment.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes due to a higher 2011 assessment as compared to 2010, partially offset by higher capitalized property taxes as compared with prior year.
Depreciation and amortization expenses increased primarily due to an increase in plant in service.
Other incomeInterest expense decreased primarily due to decreased interest earned on money pool investments anda revision in 2011 caused by FERC’s acceptance of a change in the gain recorded in 2007 on the saletreatment of non-utility property.funds received from independent power producers for transmission interconnection projects.
Income Taxes
The effective income tax rates for 2009, 2008,2012, 2011, and 20072010 were 35.3%55.6%, 35.8%20.9%, and 33.2%37.0%, respectively. The increase in the rate for 2012 and the decline in the rate for 2011 is primarily due to intercompany settle ups for federal income taxes for the effects of various tax positions settled with the IRS for years prior to 2008 which include an allocation of the tax benefit of Entergy Corporation’s expenses to the subsidiaries generating taxable income for the respective years. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate.rates.
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2009 | | 2008 | | 2007 | | 2012 | | | 2011 | | | 2010 | |
| | | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | | $1,082 | | $40,582 | | $73,417 | | $ | 16 | | | $ | 1,216 | | | $ | 91,451 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | |
| | Operating activities | | 222,019 | | 80,000 | | 169,194 | |
| | Investing activities | | (159,473) | | (133,289) | | (68,901) | |
| | Financing activities | | 27,824 | | 13,789 | | (133,128) | |
| | Net increase (decrease) in cash and cash equivalents | | 90,370 | | (39,500) | | (32,835) | |
| Net cash provided by (used in): | | | | | | | | | | | | | |
| Operating activities | | | | 202,406 | | | | 99,596 | | | | 120,107 | |
| Investing activities | | | | (391,127 | ) | | | (151,830 | ) | | | (174,096 | ) |
| Financing activities | | | | 241,675 | | | | 51,034 | | | | (36,246 | ) |
| Net increase (decrease) in cash and cash equivalents | | | | 52,954 | | | | (1,200 | ) | | | (90,235 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | | $91,452 | | $1,082 | | $40,582 | | $ | 52,970 | | | $ | 16 | | | $ | 1,216 | |
Operating Activities
Cash flowNet cash provided by operating activities increased $142$102.8 million in 2009 primarily due to increased recovery of deferred fuel costs and a decrease of $5.9 million in pension contributions, offset by an increase of $22.4 million in income tax payments.
Cash flow provided by operating activities decreased $89.2 million in 20082012 primarily due to:
| · | decreased recoverythe purchase in 2011 of deferred$42.6 million of fuel and purchased power costs;oil from System Fuels because System Fuels will no longer procure fuel oil for the Utility companies; |
| · | the receiptincome tax payments of $48$22.1 million of securitization proceeds in 2007; |
· | the timing of collections of receivables from customers and payments to vendors;2011; and |
| · | an increasea decrease of $10.9$19.5 million in pension contributions. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension funding. |
Net cash provided by operating activities decreased $20.5 million in 2011 primarily due to the purchase of $42.6 million of fuel oil inventory in 2011 from System Fuels because System Fuels will no longer procure fuel oil for the Utility companies. The decrease was partially offset by a decreasean increase in income tax payments.the recovery of fuel costs.
Investing Activities
Cash flowNet cash used in investing activities increased $26.2$239.3 million in 20092012 primarily due to the payment for the purchase of Hinds Energy Facility in November 2012 of approximately $203 million, including adjustments to the purchase price, and money pool activity, offset by decreased construction expenditures relatedactivity. See Note 15 to various fossil and distribution projects.the financial statements for a discussion of the purchase of Hinds Energy Facility.
Increases in Entergy Mississippi'sMississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi'sMississippi’s receivable from the money pool increased by $31.4$16.9 million in 2009.2012. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries'Entergy’s subsidiaries’ need for external short-term borrowings.
Cash flowNet cash used in investing activities increased $64.4decreased $22.3 million in 20082011 primarily due to a decrease in construction expenditures because of a $49 million payment in 2010 to a System Energy subsidiary for costs associated with the receiptdevelopment of proceedsnew nuclear generation at Grand Gulf and the repayment by System Fuels of Entergy Mississippi’s $5.5 million investment in 2007 from funds held in trust in 2006 that were used for the redemption in January 2007, prior to maturity, of $100 million of 4.35% Series First Mortgage Bonds, partiallySystem Fuels. The decrease was offset by the transfer in 2007 of $30.7 million to the storm damage reserve escrow account and money pool activity.
Decreases in Entergy Mississippi'sMississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi'sMississippi’s receivable from the money pool decreased by $21$31.4 million in 2008.2010.
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
Financing Activities
Cash flowNet cash provided by financing activities increased $14$190.6 million in 20092012 compared to 2011 primarily due to the issuance of $150 million of 6.64% Series first mortgage bonds in June 2009, offset by to:
| · | redemptions of $80 million of 4.65% Series first mortgage bonds and $100 million of 5.92% Series first mortgage bonds in second quarter 2011; |
| · | the issuance of $250 million of 3.1% Series first mortgage bonds in December 2012 compared to the issuance of $150 million of 6.0% Series first mortgage bonds in April 2011 and the issuance of $125 million of $3.25% Series first mortgage bonds in May 2011; and |
Decreases in Entergy Mississippi'sMississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi'sMississippi’s payable to the money pool decreased by $66$2.0 million in 2009.2012 compared to decreasing by $31.3 million in 2011.
Entergy Mississippi'sMississippi’s financing activities provided $13.8$51.0 million of cash in cash flow in 20082011 compared to using $133.1$36.2 million of cash in cash flow in 20072010 primarily due to:
| · | the issuance of $275 million of first mortgage bonds in 2011 compared to the issuance of $80 million of first mortgage bonds in 2010; and |
| · | a decrease of $40.1 million in common stock dividends. |
The net cash provided was partially offset by the redemption of $180 million of first mortgage bonds in 2011 compared to the redemption prior to maturity, of $100 million of 4.35% Series First Mortgage Bondsfirst mortgage bonds in January 20072010 and money pool activity, partially offset by an increase of $18 million in common stock dividends paid.activity.
IncreasesDecreases in Entergy Mississippi'sMississippi’s payable to the money pool are a sourceuse of cash flow, and Entergy Mississippi'sMississippi’s payable to the money pool increaseddecreased by $66$31.3 million in 2008.2011 compared to increasing by $33.3 million in 2010.
See Note 5 to the financial statements for details on long-term debt.
Capital Structure
Entergy Mississippi'sMississippi’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio is due to the issuance of $150 million of 6.64% Series first mortgage bonds in June 2009, as discussed below.
| | | December 31, 2009 | | December 31, 2008 | | December 31, 2012 | | December 31, 2011 |
| | | | | | | | | |
| Debt to capital | | | 55.9% | | 51.2% |
| Effect of subtracting cash | | | (1.2%) | | -% |
| Net debt to net capital | | 50.7% | | 49.5% | | 54.7% | | 51.2% |
| Effect of subtracting cash from debt | | 2.8% | | 0.0% | |
| Debt to capital | | 53.5% | | 49.5% | |
Net debt consists of debt less cash and cash equivalents. Debt consists of capital lease obligations and long-term debt, including the currently maturing portion. Capital consists of debt and shareholders' equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi'sMississippi’s financial condition.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy Mississippi requires capital resources for:
| · | construction and other capital investments; |
| · | debt and preferred stock maturities;maturities or retirements; |
| · | working capital purposes, including the financing of fuel and purchased power costs; and |
| · | dividend and interest payments. |
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
Following are the amounts of Entergy Mississippi'sMississippi’s planned construction and other capital investments, and existing debt obligations and lease obligations (includes estimated interest payments):.
| | 2010 | | 2011-2012 | | 2013-2014 | | After 2014 | | Total | | 2013 | | 2014-2015 | | 2016-2017 | | After 2017 | | Total |
| | (In Millions) | (In Millions) |
| Planned construction and | | | | | | | | | | | |
| capital investment (1) | $219 | | $375 | | N/A | | N/A | | $594 | | |
| Planned construction and capital investment (1): | | Planned construction and capital investment (1): | | | | | | | |
| Generation | | $20 | | $50 | | N/A | | N/A | | $70 |
| Transmission | | 50 | | 151 | | N/A | | N/A | | 201 |
| Distribution | | 87 | | 165 | | N/A | | N/A | | 252 |
| Other | | 11 | | 39 | | N/A | | N/A | | 50 |
| Total | | $168 | | $405 | | N/A | | N/A | | $573 |
| Long-term debt (2) | $50 | | $173 | | $182 | | $1,080 | | $1,485 | | $154 | | $107 | | $225 | | $1,594 | | $2,080 |
| Capital lease payments | $2 | | $4 | | $2 | | N/A | | $8 | | $3 | | $3 | | $3 | | $1 | | $10 |
| Operating leases | $6 | | $7 | | $6 | | $9 | | $28 | | $7 | | $12 | | $6 | | $6 | | $31 |
| Purchase obligations (3) | $187 | | $366 | | $351 | | $1,596 | | $2,500 | | $243 | | $472 | | $455 | | $1,856 | | $3,026 |
| (1) | Includes approximately $123$131 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems, and to support normal customer growth. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Mississippi, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Mississippi currently expects to contribute approximately $17.8$8 million to its pension plans and approximately $5$5.5 million to other postretirement plans in 2010;2013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the2013. See "Critical Accounting Estimates – Qualified Pension Protection Actand Other Postretirement Benefits" below for a discussion of 2006 rules, effective for the 2008 plan yearqualified pension and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Mississippi's pension contributions in the future.
Also, in addition to the contractual obligations, Entergy Mississippi has $8 million of unrecognized taxother postretirement benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.funding.
The planned capital investment estimate for Entergy Mississippi reflects capital required to support existing business and customer growth. Entergy'sEntergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Entergy Mississippi'sMississippi’s long-term debt indentures restrictindenture restricts the amount of retained earnings available for the payment of cash dividends or other distributions on its common and preferred stock. As of December 31, 2009,2012, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $236$68.5 million.
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
New Nuclear Generation Development Costs
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi has been developing and is developingpreserving a project option for new nuclear generation at Grand Gulf Nuclear Station. Entergy Mississippi, together with Entergy Gulf States Louisiana and Entergy Louisiana, has been engaged in the development of options to construct new nuclear generation at the Grand Gulf and River Bend Station sites. Entergy Mississippi is leading the development at Grand Gulf, and Entergy Gulf States Louisiana and Entergy Louisiana are leading the development at River Bend. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In October 2010, Entergy Mississippi paid for and has recognized on its books $49.5 million in costs associatedfiled an application with the development ofMPSC requesting that the MPSC determine that it is in the public interest to preserve the option to construct new nuclear generation at Grand Gulf; theseGulf and that the MPSC approve the deferral of Entergy Mississippi’s costs previously had been recordedincurred to date and in the future related to this project, including the accrual of AFUDC or similar carrying charges. In October 2011, Entergy Mississippi and the Mississippi Public Utilities Staff filed with the MPSC a joint stipulation that the MPSC approved in November 2011. The stipulation states that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf. The costs shall be treated as a regulatory asset until the proceeding is resolved. The Mississippi Public Utilities Staff and Entergy Mississippi also agree that the MPSC should conduct a hearing to consider the relief requested by Entergy Mississippi in its application, including evidence regarding whether costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf were prudently incurred and are otherwise allowable. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that such prudently incurred costs shall be recoverable in a manner to be determined by the MPSC. In the Stipulation, the Mississippi Public Utilities Staff and Entergy Mississippi agree that the development of a nuclear unit project option is consistent with the Mississippi Baseload Act. The Mississippi Public Utilities Staff and Entergy Mississippi further agree that the deferral of costs incurred in connection with planning, evaluation, monitoring, and other and related generation resource development activities for new nuclear generation at Grand Gulf also is consistent with the Mississippi Baseload Act. Entergy Mississippi will not accrue carrying charges or continue to accrue AFUDC on the bookscosts, pending the outcome of Entergy New Nuclear Development, LLC, a System Energy subsidiary.the proceeding. Further proceedings before the MPSC have not been scheduled.
Sources of Capital
Entergy Mississippi'sMississippi’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt or preferred stock issuances; and |
| · | bank financing under new or existing facilities. |
Entergy Mississippi may refinance, redeem, or redeemotherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Mississippi require prior regulatory approval. Preferred stock and debt issuances are also subject to issuance tests set forth in its corporate charter, bond indenture, and other agreements. Entergy Mississippi has sufficient capacity under these tests to meet its foreseeable capital needs.
In May and June 2009,2012, Entergy Mississippi renewed its twothree separate credit facilities through May 2010. In August 2009, Entergy Mississippi increased its borrowing capacity with a third line of credit which will also expire2013 in May 2010, increasing the borrowing limits to the aggregate amount of $70 million. No borrowings were outstanding under the credit facilities as of December 31, 2009.2012. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi'sMississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:years.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $31,435 | | ($66,044) | | $20,997 | | $39,573 |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $16,878 | | ($1,999) | | ($33,255) | | $31,435 |
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
In May 2007, $6.6 million of Entergy Mississippi's receivable from the money pool was replaced by a note receivable from Entergy New Orleans. See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has obtained short-term borrowing authorization from the FERC under which it may borrow through October 2011,2013, up to the aggregate amount, at any one time outstanding, of $175 million. See Note 4 to the financial statements for further discussion of Entergy Mississippi'sMississippi’s short-term borrowing limits. Entergy Mississippi has also obtained an order from the FERC authorizing long-term securities issuances through July 2011.
Entergy Mississippi, Inc.
Management's Financial Discussion and Analysis
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Mississippi charges for electricity significantly influence its financial position, results of operations, and liquidity. Entergy Mississippi is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the MPSC, is primarily responsible for approval of the rates charged to customers.
Formula Rate Plan
In September 2009, Entergy Mississippi filed with the MPSC proposed modifications to its formula rate plan rider. The proposed modifications include:In March 2010 the MPSC issued an order: (1) resettingproviding the opportunity for a reset of Entergy Mississippi's return on common equity to the middle ofa point within the formula rate plan bandwidth each year and eliminating the 50/50 sharing that had been in the current plan, (2) modifying the performance measurement process, and (3) replacing the current raterevenue change limit of two percent of revenues, which was subject to a $14.5 million revenue adjustment cap, with a proposed limit of four percent of revenues, (3) implementingalthough any adjustment above two percent requires a hearing before the MPSC. The MPSC did not approve Entergy Mississippi's request to use a projected test year for the annual filing and subsequent look-back for the prior year, and (4) modifying the performance measurement process.
In March 2009, Entergy Mississippi made with the MPSC its annual scheduled formula rate plan filing for the 2008 test year. The filing reported a $27.0 million revenue deficiency and, an earned return on common equity of 7.41%.therefore, Entergy Mississippi requestedwill continue to use a $14.5 million increase inhistorical test year for its annual electric revenues, which is the maximum increase allowedevaluation reports under the terms of the formula rate plan. The MPSC issued an order on June 30, 2009, finding that Entergy Mississippi's earned return was sufficiently below the lower bandwidth limit set by the formula rate plan to require a $14.5 million increase in annual revenues, effective for bills rendered on or after June 30, 2009.
In March 2008,2010, Entergy Mississippi madesubmitted its 2009 test year filing, its first annual scheduledfiling under the new formula rate plan filing for the 2007 test year with the MPSC. The filing showed that a $10.1 million increase in annual electric revenues is warranted.rider. In June 2008, Entergy Mississippi reached a settlement with the Mississippi Public Utilities Staff that would result in a $3.8 million rate increase. In January 2009 the MPSC rejected the settlement and left the current rates in effect. Entergy Mississippi appealed the MPSC's decision to the Mississippi Supreme Court. After the decision of the MPSC regarding the formula rate plan filing for the 2008 test year, Entergy Mississippi filed a motion to dismiss its appeal to the Mississippi Supreme Court.
In March 2007, Entergy Mississippi made its annual scheduled formula rate plan filing for the 2006 test year with the MPSC. The filing showed that an increase of $12.9 million in annual electric revenues is warranted. In June 20072010 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities staffStaff that provides for no change in rates, but does provide for the deferral as a $10.5regulatory asset of $3.9 million of legal expenses associated with certain litigation involving the Mississippi Attorney General, as well as ongoing legal expenses in that litigation until the litigation is resolved.
In March 2011, Entergy Mississippi submitted its formula rate increase,plan 2010 test year filing. The filing shows an earned return on common equity of 10.65% for the test year, which was effective beginning with July 2007 billings.is within the earnings bandwidth and results in no change in rates. In November 2011 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In March 2012, Entergy Mississippi submitted its formula rate plan filing for the 2011 test year. The filing shows an earned return on common equity of 10.92% for the test year, which is within the earnings bandwidth and results in no change in rates. In February 2013 the MPSC approved a joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff that provides for no change in rates.
In August 2012 the MPSC opened inquiries to review whether the current formulaic methodology used to calculate the return on common equity in both Entergy Mississippi’s formula rate plan and Mississippi Power Company’s annual formula rate plan are still appropriate or can be improved to better serve the public interest. The intent of this inquiry and review is for informational purposes only; the evaluation of any recommendations for changes to the existing methodology would take place in a general rate case or in the existing formula rate plan docket.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi'sMississippi’s rate schedules include an energy cost recovery rider that, effective January 1, 2013, is adjusted quarterlyannually to reflect accumulated over- or under-recoveries fromunder-recoveries. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the second prior quarter.
In July 2008 the MPSC began a proceeding to investigate the fuel procurement practices and fuel adjustment schedulesauthority of the Mississippi utility companies, including Entergy Mississippi. A two-day public hearing was held in July 2008, and after a recess during which the MPSC reviewed information, the hearing resumed on August 5, 2008, for additional testimony by an expert witness retained by the MPSC. The MPSC's witness presented testimony regarding a review of the utilities' fuel adjustment clauses. The MPSC stated that the goal of the proceeding is fact-finding so that the MPSC may decide whether to amend the current fuel cost recovery process. In February 2009 the MPSC published a final report of its expert witness, which discussed Entergy Mississippi's fuel procurement activities and made recommendations regarding fuel recovery practices in Mississippi.
In addition, in October 2008 the MPSC issued an order directing Entergy Mississippi and Entergy Services to provide documents associated with fuel adjustment clause litigation in Louisiana involving Entergy Louisiana and Entergy New Orleans, and in January 2009 issued an order requiring Entergy Mississippi to provide additional information related to the long-term Evangeline gas contract that had been an issue in the fuel adjustment clause litigation in Louisiana. Entergy Mississippi and Entergy Services filed a response
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
to the MPSC order stating that gas from the Evangeline gas contract had been sold into the Entergy System exchange and had an effect on the costs paid by Entergy Mississippi's customers. The MPSC's investigation is ongoing.
In August 2009 the MPSC retained an independent audit firm to audit Entergy Mississippi's fuel adjustment clause submittals for the period October 2007 through September 2009. The independent audit firm submitted its report to the MPSC in December 2009. The report does not recommend that any costs be disallowed for recovery. The report did suggest that some costs, less than one percent of the fuel and purchased power costs recovered during the period, may have been more reasonably charged to customers through base rates rather than through fuel charges, but the report did not suggest that customers should not have paid for those costs. In November 2009 the MPSC also retained another firm to review processes and practices related to fuel and purchased energy. The results of that review are due to the MPSC in March 2010.
In January 2010 the MPSC issued an order certifying to the Mississippi Legislature the independent audit report and the Public Utilities Staff's annual fuel audit report for the years ended September 30, 2008 and 2009, which did not find any imprudent costs. The order stated that the MPSC will open a rulemaking docket to address certain policy issues regarding allowable fuel adjustment costs, fuel adjustment mechanisms, and related matters.
Mississippi Attorney General Complaint
The Mississippi attorney general filed a complaint in state court in December 2008 against Entergy Corporation, Entergy Mississippi, Entergy Services, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud, and breach of good faith and fair dealing, and requesting an accounting and restitution. The litigationcomplaint is wide ranging and relates to tariffs and procedures under which Entergy Mississippi purchases power not generated in Mississippi to meet electricity demand. Entergy believes the complaint is unfounded. OnIn December 29, 2008 the defendant Entergy companies filed to removeremoved the attorney general'sgeneral’s suit to U.S. District Court (the forumin Jackson, Mississippi. The Mississippi attorney general moved to remand the matter to state court. In August 2012 the District Court issued an opinion denying the Attorney General’s motion for remand, finding that the District Court has subject matter jurisdiction under the Class Action Fairness Act.
The defendant Entergy believes is appropriate to resolve the types of federal issues raised in the suit), where it is currently pending, and additionallycompanies answered the complaint and filed a counter-claimcounterclaim for relief based upon the Mississippi Public Utilities Act and the Federal Power Act. The Mississippi attorney general has filed a pleading seeking to remand the matter to state court. In May 2009 the defendant Entergy companies filed a motion for judgment on the pleadings asserting grounds of federal preemption, the exclusive jurisdiction of the MPSC, and factual errors in the attorney general'sgeneral’s complaint. In September 2012 the District Court heard oral argument on Entergy’s motion for judgment on the pleadings. The District Court’s ruling on the motion for judgment on the pleadings is pending.
Storm Damage Accrual and Storm Cost Recovery
In two orders issued in July 2012 the MPSC temporarily increased Entergy Mississippi’s storm damage reserve monthly accrual from $0.75 million to $2.0 million for bills rendered during the billing months of August 2012 through December 2012, and approved recovery of $14.9 million in prudently incurred storm costs to be amortized over five months, beginning with August 2012 bills.
Federal Regulation
System Agreement Proceedings
See "“Independent Coordinator of Transmission”, “System Agreement Proceedings"”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries Management’s Financial Discussion and Analysis for a discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.these topics.
TransmissionEnvironmental Risks
See "Independent CoordinatorEntergy Mississippi’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of Transmission"toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Mississippi is in Entergy Corporationsubstantial compliance with environmental regulations currently applicable to its facilities and Subsidiaries' Management's Discussion and Analysis for further discussion.operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy Mississippi'sMississippi’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy Mississippi'sMississippi’s financial position or results of operations.
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Mississippi records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected qualified benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $629 | | $6,592 | | (0.25%) | | $966 | | $12,441 |
| Rate of return on plan assets | | (0.25%) | | $498 | | - | | (0.25%) | | $616 | | $- |
| Rate of increase in compensation | | 0.25% | | $304 | | $1,347 | | 0.25% | | $389 | | $2,222 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $367 | | $3,678 |
| Health care cost trend | | 0.25% | | $327 | | $1,700 | | 0.25% | | $561 | | $3,269 |
| Discount rate | | (0.25%) | | $187 | | $1,945 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Mississippi, Inc.
Management'sManagement’s Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for Entergy Mississippi in 20092012 was $3.4$12.3 million. Entergy Mississippi anticipates 20102013 qualified pension cost to be $7.3$15.4 million. Entergy Mississippi contributed $5.8$9.7 million to its qualified pension plans in 20092012 and anticipates that it will contribute approximately $17.8$8 million in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Mississippi's pension contributions in the future.2013.
Total postretirement health care and life insurance benefit costs for Entergy Mississippi in 20092012 were $6.5$6.4 million, including $1.6$1.8 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Mississippi expects 20102013 postretirement health care and life insurance benefit costs to approximate $5.0$4.8 million, including $1.6$1.9 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Mississippi expects to contribute approximately $5contributed $6.6 million to its other postretirement plans in 2010.2012 and expects to contribute $5.5 million in 2013.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for a discussion of new accounting pronouncements.Analysis.
To the Board of Directors and Shareholders of
Entergy Mississippi, Inc.
Jackson, Mississippi
We have audited the accompanying balance sheets of Entergy Mississippi, Inc. (the “Company”) as of December 31, 20092012 and 2008,2011, and the related income statements, statements of income, retained earnings, and cash flows, and statements of changes in common equity (pages 336354 through 340358 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy Mississippi, Inc. as of December 31, 20092012 and 2008,2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,120,366 | | | $ | 1,266,470 | | | $ | 1,232,922 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 227,133 | | | | 363,025 | | | | 277,806 | |
| Purchased power | | | 320,923 | | | | 339,061 | | | | 383,769 | |
| Other operation and maintenance | | | 244,722 | | | | 210,657 | | | | 217,354 | |
| Taxes other than income taxes | | | 75,006 | | | | 69,759 | | | | 66,841 | |
| Depreciation and amortization | | | 97,768 | | | | 93,119 | | | | 89,875 | |
| Other regulatory charges (credits) - net | | | (5,701 | ) | | | 9,460 | | | | 16,001 | |
| TOTAL | | | 959,851 | | | | 1,085,081 | | | | 1,051,646 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 160,515 | | | | 181,389 | | | | 181,276 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 3,955 | | | | 7,755 | | | | 6,655 | |
| Interest and investment income | | | 170 | | | | 249 | | | | 416 | |
| Miscellaneous - net | | | (3,951 | ) | | | (3,904 | ) | | | (804 | ) |
| TOTAL | | | 174 | | | | 4,100 | | | | 6,267 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 57,345 | | | | 52,273 | | | | 55,774 | |
| Allowance for borrowed funds used during construction | | | (2,103 | ) | | | (4,314 | ) | | | (3,719 | ) |
| TOTAL | | | 55,242 | | | | 47,959 | | | | 52,055 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 105,447 | | | | 137,530 | | | | 135,488 | |
| | | | | | | | | | | | | |
| Income taxes | | | 58,679 | | | | 28,801 | | | | 50,111 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 46,768 | | | | 108,729 | | | | 85,377 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 2,828 | | | | 2,828 | | | | 2,828 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 43,940 | | | $ | 105,901 | | | $ | 82,549 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 46,768 | | | $ | 108,729 | | | $ | 85,377 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | |
| Depreciation and amortization | | | 97,768 | | | | 93,119 | | | | 89,875 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 58,221 | | | | (3,443 | ) | | | 48,744 | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | 42,222 | | | | 5,488 | | | | (42,790 | ) |
| Fuel inventory | | | (6,202 | ) | | | (35,621 | ) | | | (1,003 | ) |
| Accounts payable | | | (3,796 | ) | | | (7,059 | ) | | | 1,906 | |
| Taxes accrued | | | 6,791 | | | | 13,535 | | | | (12,817 | ) |
| Interest accrued | | | (3,324 | ) | | | 456 | | | | 1,915 | |
| Deferred fuel costs | | | (42,331 | ) | | | 18,998 | | | | (76,064 | ) |
| Other working capital accounts | | | (6,859 | ) | | | (27,480 | ) | | | 46,101 | |
| Provisions for estimated losses | | | (2,469 | ) | | | (1,177 | ) | | | (1,937 | ) |
| Other regulatory assets | | | (6,501 | ) | | | (83,399 | ) | | | (5,780 | ) |
| Pension and other postretirement liabilities | | | 16,782 | | | | 39,183 | | | | (6,525 | ) |
| Other assets and liabilities | | | 5,336 | | | | (21,733 | ) | | | (6,895 | ) |
| Net cash flow provided by operating activities | | | 202,406 | | | | 99,596 | | | | 120,107 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (175,544 | ) | | | (165,998 | ) | | | (223,787 | ) |
| Allowance for equity funds used during construction | | | 3,955 | | | | 7,755 | | | | 6,655 | |
| Proceeds from sale of assets | | | - | | | | 868 | | | | 3,951 | |
| Payment for purchase of plant | | | (202,668 | ) | | | - | | | | - | |
| Change in money pool receivable - net | | | (16,878 | ) | | | - | | | | 31,435 | |
| Changes in other investments - net | | | 8 | | | | 18 | | | | 7,615 | |
| Investments in affiliates | | | - | | | | 5,527 | | | | - | |
| Other | | | - | | | | - | | | | 35 | |
| Net cash flow used in investing activities | | | (391,127 | ) | | | (151,830 | ) | | | (174,096 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 246,502 | | | | 268,418 | | | | 76,727 | |
| Retirement of long-term debt | | | - | | | | (180,000 | ) | | | (100,000 | ) |
| Change in money pool payable - net | | | (1,999 | ) | | | (31,256 | ) | | | 33,255 | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | - | | | | (3,300 | ) | | | (43,400 | ) |
| Preferred stock | | | (2,828 | ) | | | (2,828 | ) | | | (2,828 | ) |
| Net cash flow provided by (used in) financing activities | | | 241,675 | | | | 51,034 | | | | (36,246 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 52,954 | | | | (1,200 | ) | | | (90,235 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 16 | | | | 1,216 | | | | 91,451 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 52,970 | | | $ | 16 | | | $ | 1,216 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 58,043 | | | $ | 49,192 | | | $ | 51,250 | |
| Income taxes | | $ | (696 | ) | | $ | 22,094 | | | $ | 16,401 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 585 | | | $ | 7 | |
| Temporary cash investments | | | 52,385 | | | | 9 | |
| Total cash and cash equivalents | | | 52,970 | | | | 16 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 49,836 | | | | 51,026 | |
| Allowance for doubtful accounts | | | (910 | ) | | | (756 | ) |
| Associated companies | | | 25,504 | | | | 51,329 | |
| Other | | | 11,072 | | | | 13,924 | |
| Accrued unbilled revenues | | | 43,045 | | | | 38,368 | |
| Total accounts receivable | | | 128,547 | | | | 153,891 | |
| Deferred fuel costs | | | 26,490 | | | | - | |
| Accumulated deferred income taxes | | | 44,027 | | | | 11,694 | |
| Fuel inventory - at average cost | | | 48,778 | | | | 42,499 | |
| Materials and supplies - at average cost | | | 40,331 | | | | 35,716 | |
| Prepayments and other | | | 5,329 | | | | 4,666 | |
| TOTAL | | | 346,472 | | | | 248,482 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Non-utility property - at cost (less accumulated depreciation) | | | 4,698 | | | | 4,725 | |
| Escrow accounts | | | 61,836 | | | | 31,844 | |
| TOTAL | | | 66,534 | | | | 36,569 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,708,743 | | | | 3,274,031 | |
| Property under capital lease | | | 8,112 | | | | 10,721 | |
| Construction work in progress | | | 62,876 | | | | 105,083 | |
| TOTAL UTILITY PLANT | | | 3,779,731 | | | | 3,389,835 | |
| Less - accumulated depreciation and amortization | | | 1,324,627 | | | | 1,210,092 | |
| UTILITY PLANT - NET | | | 2,455,104 | | | | 2,179,743 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 63,614 | | | | 65,196 | |
| Other regulatory assets | | | 401,471 | | | | 393,387 | |
| Other | | | 20,832 | | | | 20,017 | |
| TOTAL | | | 485,917 | | | | 478,600 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 3,354,027 | | | $ | 2,943,394 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 100,000 | | | $ | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 42,398 | | | | 46,311 | |
| Other | | | 44,856 | | | | 41,489 | |
| Customer deposits | | | 71,182 | | | | 68,610 | |
| Taxes accrued | | | 52,327 | | | | 45,536 | |
| Interest accrued | | | 18,226 | | | | 21,550 | |
| Deferred fuel costs | | | - | | | | 15,841 | |
| Accumulated deferred income taxes | | | 218 | | | | - | |
| Other | | | 21,490 | | | | 17,474 | |
| TOTAL | | | 350,697 | | | | 256,811 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 761,812 | | | | 672,129 | |
| Accumulated deferred investment tax credits | | | 7,257 | | | | 6,372 | |
| Obligations under capital lease | | | 5,329 | | | | 8,112 | |
| Other regulatory liabilities | | | 1,235 | | | | - | |
| Asset retirement cost liabilities | | | 6,039 | | | | 5,697 | |
| Accumulated provisions | | | 35,820 | | | | 38,289 | |
| Pension and other postretirement liabilities | | | 160,866 | | | | 144,088 | |
| Long-term debt | | | 1,069,519 | | | | 920,439 | |
| Other | | | 25,426 | | | | 5,370 | |
| TOTAL | | | 2,073,303 | | | | 1,800,496 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 50,381 | | | | 50,381 | |
| | | | | | | | | |
| COMMON EQUITY | | | | | | | | |
| Common stock, no par value, authorized 12,000,000 | | | | | | | | |
| shares; issued and outstanding 8,666,357 shares in 2012 and 2011 | | | 199,326 | | | | 199,326 | |
| Capital stock expense and other | | | (690 | ) | | | (690 | ) |
| Retained earnings | | | 681,010 | | | | 637,070 | |
| TOTAL | | | 879,646 | | | | 835,706 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 3,354,027 | | | $ | 2,943,394 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| STATEMENTS OF CHANGES IN COMMON EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | Common Equity | | | | |
| | | Common Stock | | | Capital Stock Expense and Other | | | Retained Earnings | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 199,326 | | | $ | (690 | ) | | $ | 495,320 | | | $ | 693,956 | |
| Net income | | | - | | | | - | | | | 85,377 | | | | 85,377 | |
| Common stock dividends | | | - | | | | - | | | | (43,400 | ) | | | (43,400 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (2,828 | ) | | | (2,828 | ) |
| Balance at December 31, 2010 | | $ | 199,326 | | | $ | (690 | ) | | $ | 534,469 | | | $ | 733,105 | |
| Net income | | | - | | | | - | | | | 108,729 | | | | 108,729 | |
| Common stock dividends | | | - | | | | - | | | | (3,300 | ) | | | (3,300 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (2,828 | ) | | | (2,828 | ) |
| Balance at December 31, 2011 | | $ | 199,326 | | | $ | (690 | ) | | $ | 637,070 | | | $ | 835,706 | |
| Net income | | | - | | | | - | | | | 46,768 | | | | 46,768 | |
| Preferred stock dividends | | | - | | | | - | | | | (2,828 | ) | | | (2,828 | ) |
| Balance at December 31, 2012 | | $ | 199,326 | | | $ | (690 | ) | | $ | 681,010 | | | $ | 879,646 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,177,304 | | | $ | 1,462,182 | | | $ | 1,372,802 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 340,804 | | | | 456,730 | | | | 456,346 | |
| Purchased power | | | 359,664 | | | | 468,219 | | | | 414,763 | |
| Other operation and maintenance | | | 217,452 | | | | 216,554 | | | | 202,952 | |
| Taxes other than income taxes | | | 63,381 | | | | 63,807 | | | | 62,516 | |
| Depreciation and amortization | | | 86,872 | | | | 83,297 | | | | 79,470 | |
| Other regulatory charges (credits) - net | | | (57,056 | ) | | | 38,385 | | | | 14,810 | |
| TOTAL | | | 1,011,117 | | | | 1,326,992 | | | | 1,230,857 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 166,187 | | | | 135,190 | | | | 141,945 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 2,964 | | | | 2,966 | | | | 3,900 | |
| Interest and dividend income | | | 863 | | | | 1,778 | | | | 5,572 | |
| Miscellaneous - net | | | (564 | ) | | | (2,047 | ) | | | 1,011 | |
| TOTAL | | | 3,263 | | | | 2,697 | | | | 10,483 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 47,414 | | | | 41,560 | | | | 41,699 | |
| Other interest - net | | | 3,868 | | | | 5,328 | | | | 5,321 | |
| Allowance for borrowed funds used during construction | | | (1,791 | ) | | | (1,951 | ) | | | (2,548 | ) |
| TOTAL | | | 49,491 | | | | 44,937 | | | | 44,472 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 119,959 | | | | 92,950 | | | | 107,956 | |
| | | | | | | | | | | | | |
| Income taxes | | | 42,323 | | | | 33,240 | | | | 35,850 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 77,636 | | | | 59,710 | | | | 72,106 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 2,828 | | | | 2,828 | | | | 2,768 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 74,808 | | | $ | 56,882 | | | $ | 69,338 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 77,636 | | | $ | 59,710 | | | $ | 72,106 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Other regulatory charges (credits) - net | | | (57,056 | ) | | | 38,385 | | | | 14,810 | |
| Depreciation and amortization | | | 86,872 | | | | 83,297 | | | | 79,470 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 15,923 | | | | 32,031 | | | | (17,123 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 44,050 | | | | (46,490 | ) | | | 898 | |
| Fuel inventory | | | 3,413 | | | | 1,078 | | | | (2,721 | ) |
| Accounts payable | | | 3,511 | | | | 3,950 | | | | (13,379 | ) |
| Taxes accrued | | | 707 | | | | 4,858 | | | | (9,649 | ) |
| Interest accrued | | | 2,066 | | | | 1,919 | | | | 2,131 | |
| Deferred fuel costs | | | 77,932 | | | | (81,607 | ) | | | (18,654 | ) |
| Other working capital accounts | | | (37,373 | ) | | | 43,534 | | | | (12,432 | ) |
| Provision for estimated losses and reserves | | | 4,446 | | | | (13,307 | ) | | | 40,228 | |
| Changes in other regulatory assets | | | (43,807 | ) | | | (98,387 | ) | | | 37,381 | |
| Changes in pension and other postretirement liabilities | | | (6,786 | ) | | | 61,277 | | | | (7,658 | ) |
| Other | | | 50,484 | | | | (10,248 | ) | | | 3,786 | |
| Net cash flow provided by operating activities | | | 222,018 | | | | 80,000 | | | | 169,194 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (130,907 | ) | | | (156,224 | ) | | | (156,643 | ) |
| Allowance for equity funds used during construction | | | 2,964 | | | | 2,966 | | | | 3,900 | |
| Proceeds from sale of assets | | | - | | | | - | | | | 2,616 | |
| Change in money pool receivable - net | | | (31,435 | ) | | | 20,997 | | | | 11,974 | |
| Changes in other temporary investments - net | | | - | | | | - | | | | 100,000 | |
| Payment to storm reserve escrow account | | | (175 | ) | | | (944 | ) | | | (30,748 | ) |
| Other | | | 80 | | | | (84 | ) | | | - | |
| Net cash flow used in investing activities | | | (159,473 | ) | | | (133,289 | ) | | | (68,901 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 147,996 | | | | 28,873 | | | | - | |
| Retirement of long-term debt | | | - | | | | (30,000 | ) | | | (100,000 | ) |
| Change in money pool payable - net | | | (66,044 | ) | | | 66,044 | | | | - | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (51,300 | ) | | | (48,300 | ) | | | (30,300 | ) |
| Preferred stock | | | (2,828 | ) | | | (2,828 | ) | | | (2,828 | ) |
| Net cash flow provided by (used in) financing activities | | | 27,824 | | | | 13,789 | | | | (133,128 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 90,369 | | | | (39,500 | ) | | | (32,835 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 1,082 | | | | 40,582 | | | | 73,417 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 91,451 | | | $ | 1,082 | | | $ | 40,582 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | |
| Cash paid during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 47,007 | | | $ | 42,960 | | | $ | 42,479 | |
| Income taxes | | $ | 23,478 | | | $ | 1,055 | | | $ | 48,914 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 1,147 | | | $ | 1,072 | |
| Temporary cash investment | | | 90,304 | | | | 10 | |
| Total cash and cash equivalents | | | 91,451 | | | | 1,082 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 50,092 | | | | 76,503 | |
| Allowance for doubtful accounts | | | (1,018 | ) | | | (687 | ) |
| Associated companies | | | 36,565 | | | | 29,291 | |
| Other | | | 12,842 | | | | 11,675 | |
| Accrued unbilled revenues | | | 41,137 | | | | 35,451 | |
| Total accounts receivable | | | 139,618 | | | | 152,233 | |
| Note receivable - Entergy New Orleans | | | 7,610 | | | | - | |
| Deferred fuel costs | | | - | | | | 5,025 | |
| Accumulated deferred income taxes | | | 294 | | | | 19,335 | |
| Fuel inventory - at average cost | | | 5,875 | | | | 9,288 | |
| Materials and supplies - at average cost | | | 37,979 | | | | 31,921 | |
| Prepayments and other | | | 2,820 | | | | 6,290 | |
| TOTAL | | | 285,647 | | | | 225,174 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 5,535 | | | | 5,615 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 4,864 | | | | 5,000 | |
| Storm reserve escrow account | | | 31,867 | | | | 31,692 | |
| Note receivable - Entergy New Orleans | | | - | | | | 7,610 | |
| TOTAL | | | 42,266 | | | | 49,917 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,070,109 | | | | 2,951,636 | |
| Property under capital lease | | | 6,418 | | | | 7,806 | |
| Construction work in progress | | | 62,866 | | | | 81,959 | |
| TOTAL UTILITY PLANT | | | 3,139,393 | | | | 3,041,401 | |
| Less - accumulated depreciation and amortization | | | 1,115,756 | | | | 1,058,426 | |
| UTILITY PLANT - NET | | | 2,023,637 | | | | 1,982,975 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 34,114 | | | | 23,693 | |
| Other regulatory assets | | | 251,407 | | | | 226,933 | |
| Other | | | 19,564 | | | | 19,451 | |
| TOTAL | | | 305,085 | | | | 270,077 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 2,656,635 | | | $ | 2,528,143 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | | | | | | | |
| | | December 31, | |
| | | | 2009 | | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Accounts payable: | | | | | | | | |
| Associated companies | | $ | 58,421 | | | $ | 115,876 | |
| Other | | | 31,176 | | | | 39,623 | |
| Customer deposits | | | 62,316 | | | | 58,517 | |
| Taxes accrued | | | 41,603 | | | | 40,896 | |
| Interest accrued | | | 19,179 | | | | 17,113 | |
| Deferred fuel costs | | | 72,907 | | | | - | |
| System agreement cost equalization | | | - | | | | 23,000 | |
| Gas hedge contracts | | | - | | | | 15,610 | |
| Other | | | 5,399 | | | | 5,373 | |
| TOTAL | | | 291,001 | | | | 316,008 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 578,759 | | | | 571,193 | |
| Accumulated deferred investment tax credits | | | 7,514 | | | | 8,605 | |
| Obligations under capital lease | | | 4,949 | | | | 6,418 | |
| Other regulatory liabilities | | | 2,905 | | | | 22,331 | |
| Asset retirement cost liabilities | | | 5,071 | | | | 4,784 | |
| Accumulated provisions | | | 41,403 | | | | 36,957 | |
| Pension and other postretirement liabilities | | | 111,437 | | | | 118,223 | |
| Long-term debt | | | 845,304 | | | | 695,330 | |
| Other | | | 29,146 | | | | 32,656 | |
| TOTAL | | | 1,626,488 | | | | 1,496,497 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 50,381 | | | | 50,381 | |
| | | | | | | | | |
| SHAREHOLDERS' EQUITY | | | | | | | | |
| Common stock, no par value, authorized 12,000,000 | | | | | | | | |
| shares; issued and outstanding 8,666,357 shares in 2009 and 2008 | | | 199,326 | | | | 199,326 | |
| Capital stock expense and other | | | (690 | ) | | | (690 | ) |
| Retained earnings | | | 490,129 | | | | 466,621 | |
| TOTAL | | | 688,765 | | | | 665,257 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 2,656,635 | | | $ | 2,528,143 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| STATEMENTS OF RETAINED EARNINGS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Retained Earnings, January 1 | | $ | 466,621 | | | $ | 458,039 | | | $ | 419,001 | |
| | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | |
| Net income | | | 77,636 | | | | 59,710 | | | | 72,106 | |
| | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 2,828 | | | | 2,828 | | | | 2,768 | |
| Dividends declared on common stock | | | 51,300 | | | | 48,300 | | | | 30,300 | |
| Total | | | 54,128 | | | | 51,128 | | | | 33,068 | |
| | | | | | | | | | | | | |
| Retained Earnings, December 31 | | $ | 490,129 | | | $ | 466,621 | | | $ | 458,039 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 1,177,304 | | | $ | 1,462,182 | | | $ | 1,372,802 | | | $ | 1,450,008 | | | $ | 1,306,543 | |
| Net Income | | $ | 77,636 | | | $ | 59,710 | | | $ | 72,106 | | | $ | 52,285 | | | $ | 62,103 | |
| Total assets | | $ | 2,656,635 | | | $ | 2,528,143 | | | $ | 2,386,269 | | | $ | 2,440,891 | | | $ | 2,311,043 | |
| Long-term obligations (1) | | $ | 850,253 | | | $ | 701,748 | | | $ | 703,072 | | | $ | 795,187 | | | $ | 695,157 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 467 | | | $ | 556 | | | $ | 500 | | | $ | 568 | | | $ | 503 | |
| Commercial | | | 395 | | | | 482 | | | | 428 | | | | 484 | | | | 421 | |
| Industrial | | | 147 | | | | 199 | | | | 185 | | | | 236 | | | | 209 | |
| Governmental | | | 37 | | | | 44 | | | | 40 | | | | 45 | | | | 41 | |
| Total retail | | | 1,046 | | | | 1,281 | | | | 1,153 | | | | 1,333 | | | | 1,174 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 49 | | | | 93 | | | | 139 | | | | 43 | | | | 62 | |
| Non-associated companies | | | 28 | | | | 36 | | | | 33 | | | | 37 | | | | 37 | |
| Other | | | 54 | | | | 52 | | | | 48 | | | | 37 | | | | 34 | |
| Total | | $ | 1,177 | | | $ | 1,462 | | | $ | 1,373 | | | $ | 1,450 | | | $ | 1,307 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 5,358 | | | | 5,354 | | | | 5,474 | | | | 5,387 | | | | 5,333 | |
| Commercial | | | 4,756 | | | | 4,841 | | | | 4,872 | | | | 4,746 | | | | 4,630 | |
| Industrial | | | 2,178 | | | | 2,565 | | | | 2,771 | | | | 2,927 | | | | 2,967 | |
| Governmental | | | 405 | | | | 411 | | | | 421 | | | | 417 | | | | 411 | |
| Total retail | | | 12,697 | | | | 13,171 | | | | 13,538 | | | | 13,477 | | | | 13,341 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 198 | | | | 534 | | | | 1,025 | | | | 469 | | | | 516 | |
| Non-associated companies | | | 330 | | | | 401 | | | | 468 | | | | 431 | | | | 420 | |
| Total | | | 13,225 | | | | 14,106 | | | | 15,031 | | | | 14,377 | | | | 14,277 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 1,120,366 | | | $ | 1,266,470 | | | $ | 1,232,922 | | | $ | 1,180,107 | | | $ | 1,464,699 | |
| Net Income | | $ | 46,768 | | | $ | 108,729 | | | $ | 85,377 | | | $ | 79,367 | | | $ | 61,264 | |
| Total assets | | $ | 3,354,027 | | | $ | 2,943,394 | | | $ | 2,772,778 | | | $ | 2,689,933 | | | $ | 2,533,746 | |
| Long-term obligations (1) | | $ | 1,125,229 | | | $ | 978,932 | | | $ | 806,506 | | | $ | 900,634 | | | $ | 752,129 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt), noncurrent capital lease obligations, and preferred stock without sinking fund. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 454 | | | $ | 490 | | | $ | 509 | | | $ | 467 | | | $ | 556 | |
| Commercial | | | 381 | | | | 401 | | | | 406 | | | | 395 | | | | 482 | |
| Industrial | | | 140 | | | | 146 | | | | 145 | | | | 147 | | | | 199 | |
| Governmental | | | 37 | | | | 37 | | | | 38 | | | | 37 | | | | 44 | |
| Total retail | | | 1,012 | | | | 1,074 | | | | 1,098 | | | | 1,046 | | | | 1,281 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 23 | | | | 104 | | | | 55 | | | | 52 | | | | 96 | |
| Non-associated companies | | | 24 | | | | 27 | | | | 33 | | | | 28 | | | | 36 | |
| Other | | | 61 | | | | 61 | | | | 47 | | | | 54 | | | | 52 | |
| Total | | $ | 1,120 | | | $ | 1,266 | | | $ | 1,233 | | | $ | 1,180 | | | $ | 1,465 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 5,550 | | | | 5,848 | | | | 6,077 | | | | 5,358 | | | | 5,354 | |
| Commercial | | | 4,915 | | | | 4,985 | | | | 5,000 | | | | 4,756 | | | | 4,841 | |
| Industrial | | | 2,400 | | | | 2,326 | | | | 2,250 | | | | 2,178 | | | | 2,565 | |
| Governmental | | | 408 | | | | 415 | | | | 416 | | | | 405 | | | | 411 | |
| Total retail | | | 13,273 | | | | 13,574 | | | | 13,743 | | | | 12,697 | | | | 13,171 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 232 | | | | 431 | | | | 268 | | | | 198 | | | | 534 | |
| Non-associated companies | | | 265 | | | | 332 | | | | 402 | | | | 330 | | | | 401 | |
| Total | | | 13,770 | | | | 14,337 | | | | 14,413 | | | | 13,225 | | | | 14,106 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
ENTERGY NEW ORLEANS, INC.
Plan to Spin Off the Utility’s Transmission Business
See the “Plan to Spin Off the Utility’s Transmission Business” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt and preferred securities.
Hurricane Isaac
In August 2012, Hurricane Isaac caused extensive damage to Entergy New Orleans’s service area. The storm resulted in widespread power outages, significant damage primarily to distribution infrastructure, and the loss of sales during the power outages. Total restoration costs for the repair and/or replacement of Entergy New Orleans’s electric facilities damaged by Hurricane Isaac are currently estimated to be approximately $48 million. Entergy New Orleans is considering all reasonable avenues to recover storm-related costs from Hurricane Isaac, including, but not limited to, accessing funded storm reserves; securitization or other alternative financing; and traditional retail recovery on an interim and permanent basis. In November 2012, Entergy New Orleans drew $10 million from its funded storm reserves. Storm cost recovery or financing may be subject to review by applicable regulatory authorities.
Entergy New Orleans recorded accruals for the estimated costs incurred that were necessary to return customers to service. Entergy New Orleans recorded corresponding regulatory assets of approximately $18 million and construction work in progress of approximately $30 million. Entergy New Orleans recorded the regulatory assets in accordance with its accounting policies and based on the historic treatment of such costs in its service area because management believes that recovery through some form of regulatory mechanism is probable. Because Entergy New Orleans has not gone through the regulatory process regarding these storm costs, however, there is an element of risk, and Entergy New Orleans is unable to predict with certainty the degree of success it may have in its recovery initiatives, the amount of restoration costs that it may ultimately recover, or the timing of such recovery.
Results of Operations
Net Income
20092012 Compared to 20082011
Net income decreased $3.9$18.9 million primarily due to higher other operation and maintenance expenses and lower net revenue and lower other income, partially offset by lower interest expense and a lower effective income tax rate.revenue.
20082011 Compared to 20072010
Net income increased $10.4$4.9 million primarily due to higher net revenue, lower other operation and maintenance expenses, lower taxes other than income taxes, a lower effective income tax rate, and lower interest expense, partially offset by lower other incomenet revenue.
Entergy New Orleans, Inc.
Management’s Financial Discussion and higher taxes other than income taxes.Analysis
Net Revenue
20092012 Compared to 20082011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20092012 to 2008.2011.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $252.7 |
Effect of rate case settlement | | (14.4) |
Price applied to unbilled sales | | (4.1) |
Volume/weather | | 9.2 |
Other | | (0.4) |
2009 net revenue | | $243.0 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 247.0 | |
| Retail electric price | | | (6.2 | ) |
| Volume/weather | | | (4.8 | ) |
| Other | | | 1.9 | |
| 2012 net revenue | | $ | 237.9 | |
The effect ofretail electric price variance is primarily due to a formula rate case settlement variance results from the April 2009 settlement of Entergy New Orleans’ rate case, and includes the effects of realigning non-fuel costs associated with the operation of Grand Gulf from the fuel adjustment clause to electric base ratesplan decrease effective June 2009.October 2011. See Note 2 to the financial statements for furthera discussion of the formula rate case settlement.
The price applied to unbilled sales variance results from a decline in natural gas and purchased power prices.plan filing.
The volume/weather variance is primarily due to an increase in electricity usage in the service territory, and more favorableeffect of milder weather, in 2009as compared to the sameprior period, in 2008. Entergy New Orleans estimates that approximately 150,000 electric customerson residential and 96,000 gas customers have returned sincecommercial sales and the effects of the power outages caused by Hurricane Katrina and are taking service as of December 31, 2009, compared to approximately 141,000 electric customers and 93,000 gas customers as of December 31, 2008. Billed retail electricity usage increased a total of 238 GWh compared to the same period in 2008, an increase of 5.3%.Isaac.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues decreased primarily due to:
| · | a decrease of $107.5 million in electric fuel cost recovery revenues due to lower fuel rates offset by higher electricity usage; |
· | a decrease of $74.8$53.3 million in gross wholesale revenue primarily due to a decrease in the average price of energy available for resale sales;decreased sales to affiliate customers; and |
| · | a decrease of $37$18.9 million in gross gas revenues primarily due to lower fuel cost recovery revenues.revenues as a result of lower fuel rates and the effect of milder weather. Entergy New Orleans’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements. |
Fuel and purchased power expenses decreased primarily due to decreasesa decrease in demand for gas-fired generation and a decrease in the average market pricesprice of natural gas, and purchased power, partially offset by an increase in demand.the average market price of purchased power.
20082011 Compared to 20072010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges.charges (credits). Following is an analysis of the change in net revenue comparing 20082011 to 2007.2010.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $231.0 |
Volume/weather | | 15.5 |
Net gas revenue | | 6.6 |
Rider revenue | | 3.9 |
Base revenue | | (11.3) |
Other | | 7.0 |
2008 net revenue | | $252.7 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 272.9 | |
| Retail electric price | | | (16.9 | ) |
| Net gas revenue | | | (9.1 | ) |
| Gas cost recovery asset | | | (3.0 | ) |
| Volume/weather | | | 5.4 | |
| Other | | | (2.3 | ) |
| 2011 net revenue | | $ | 247.0 | |
The volume/weatherretail electric price variance is primarily due to an increase in electricity usage in the service territory in 2008 comparedformula rate plan decreases effective October 2010 and October 2011. See Note 2 to the same period in 2007. financial statements for a discussion of the formula rate plan filing.
Entergy New Orleans, estimates that approximately 141,000 electric customersInc.
Management’s Financial Discussion and 93,000 gas customers have returned since Hurricane Katrina and are taking service as of December 31, 2008, compared to approximately 132,000 electric customers and 86,000 gas customers as of December 31, 2007. Billed retail electricity usage increased a total of 184 GWh compared to the same period in 2007, an increase of 4%.Analysis
The net gas revenue variance is primarily due to an increasemilder weather in base rates2011 compared to 2010.
The gas cost recovery asset variance is primarily due to the recognition in March2010 of a $3 million gas operations regulatory asset associated with the settlement of Entergy New Orleans’s electric and November 2007. Refer togas formula rate plan case and the amortization of that asset. See Note 2 to the financial statements for aadditional discussion of the baseformula rate increase.plan settlement.
The rider revenue variance is due primarily to higher total revenue and a storm reserve rider effective March 2007 as a result of the City Council's approval of a settlement agreement in October 2006. The approved storm reserve has been set to collect $75 million over a ten-year period through the rider and the funds will be held in a restricted escrow account. The settlement agreement is discussed in Note 2 to the financial statements.
The base revenuevolume/weather variance is primarily due to an increase in electricity usage in the residential and commercial sectors due in part to a base rate recovery credit, effective January 2008. The base rate credit is discussed4% increase in Note 2 to the financial statements.average number of residential customers and a 3% increase in the average number of commercial customers, partially offset by the effect of less favorable weather on residential sales.
Gross operating revenues and fuel and purchased power expenses
Gross operating revenues increaseddecreased primarily due to:
| · | an increasea decrease of $58.9 million in gross wholesale revenue due to increased sales to affiliated customers and an increase in the average price of energy available for resale sales; |
· | an increase of $47.7$16.2 million in electric fuel cost recovery revenues due to higherlower fuel rates and increased electricity usage; andrates; |
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
| · | an increasea decrease of $22$15.4 million in gross gas revenues primarily due to higherlower fuel cost recovery revenues as a result of lower fuel rates and increases in gas base rates in March 2007the effect of milder weather; and November 2007. |
| · | formula rate plan decreases effective October 2010 and October 2011, as discussed above. |
Fuel and purchased power expenses increased primarily due to increases in the average market prices of natural gas and purchased power in addition toThe decrease was partially offset by an increase in demand.gross wholesale revenue due to increased sales to affiliated customers and more favorable volume/weather, as discussed above.
Other Income Statement Variances
20092012 Compared to 20082011
Other operation and maintenance expenses increased primarily due to the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’s 2010 test year formula rate plan filing approved by the City Council in September 2011. See Note 2 to the financial statements for more discussion of the 2010 test year formula rate plan filing and settlement.
2011 Compared to 2010
Other operation and maintenance expenses decreased primarily due to the deferral in 2011 of $13.4 million of 2010 Michoud plant maintenance costs pursuant to the settlement of Entergy New Orleans’s 2010 test year formula rate plan filing approved by the City Council in September 2011 and a decrease of $8.0 million in fossil-fueled generation expenses due to higher plant outage costs in 2010 due to a greater scope of work at the Michoud plant. See Note 2 to the financial statements for more discussion of the 2010 test year formula rate plan filing.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower electric and gas retail revenues as compared with the interest rate earned on money pool investments.same period in 2010.
Interest and other chargesexpense decreased primarily due to a decreasethe repayment in May 2010 of the interest rate on notes payable issued to affiliates as part of Entergy New Orleans'Orleans’s plan of reorganization as described more fullyand the repayment, at maturity, of $30 million of 4.98% Series first mortgage bonds in Note 18 to the financial statements.
2008 Compared to 2007
Other operation and maintenance expenses decreased primarily due to:
· | a provision for storm-related bad debts of $11 million recorded in 2007; |
· | a decrease of $6.2 million in legal and professional fees; |
· | a decrease of $3.4 million in employee benefit expenses; and |
· | a decrease of $1.9 million in gas operations spending due to higher labor and material costs for reliability work in 2007. |
The decrease was partially offset by:
· | an increase of $3 million due to the accrual of Energy Efficiency and Economic Development Funds; |
· | an increase of $3 million in outside regulatory consultant fees; and |
· | an increase of $2.7 million in loss reserves primarily due to the implementation of the storm reserve rider in March 2007. The storm reserve rider is discussed above under "Net Revenue."
|
Taxes other than income taxes increased primarily due to higher franchise taxes in 2008 as a result of higher revenues.
Other income decreased due to a reduction in the allowance for equity funds used during construction related to a decrease in storm-related construction and lower carrying costs due to the reduction of the Hurricane Katrina storm costs regulatory asset.July 2010.
Income Taxes
The effective income tax rates for 2009, 2008,2012, 2011, and 20072010 were 33.6%29.8%, 39.7%30.6%, and 35.5%34.8%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.rates.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Hurricane Katrina
In August 2005, Hurricane Katrina caused catastrophic damage to Entergy New Orleans'Orleans’s service territory, including the effect of extensive flooding that resulted from levee breaks in and around the New Orleans area. The storms and flooding resulted in power outages; significant damage to electric distribution, transmission, and generation and gas infrastructure; and the loss of sales and customers due to mandatory evacuations and the destruction of homes and businesses.territory. Entergy pursued a broad range of initiatives to recover storm restoration and business continuity costs. Initiatives included obtaining reimbursement of certain costs, covered by insurance,including obtaining assistance through federal legislation for damage caused by Hurricanes Katrina and Rita, and pursuing recovery through existing or new rate mechanisms regulated by the FERC and the City Council.Hurricane Katrina.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Community Development Block Grant (CDBG)
In December 2005, the U.S. Congress passed the Katrina Relief Bill, a hurricane aid package that included CDBG funding (for the states affected by Hurricanes Katrina, Rita, and Wilma) that allowed state and local leaders to fund individual recovery priorities. In March 2007 the City Council certified that Entergy New Orleans incurred $205 million in storm-related costs through December 2006 that are eligible for CDBG funding under the state action plan, and certified Entergy New Orleans'Orleans’s estimated costs of $465 million for its gas system rebuild (which is discussed below). Entergy New Orleans received $180.8 million of CDBG funds in 2007.
Insurance Claims
Entergy has received a total of $3172007 and $19.2 million as of December 31, 2009 on its Hurricane Katrina and Hurricane Rita insurance claims, including the settlements of its Hurricane Katrina claims with each of its two excess insurers. Of the $317 million received, $206 million was allocated to Entergy New Orleans. Entergy has substantially completed its insurance recoveries related to Hurricane Katrina and Hurricane Rita.
Rate and Storm-related Riders Filings
See "Formula Rate Plans and Storm-related Riders" below for a discussion of Entergy New Orleans' June 2006 formula rate plan filings and request to implement two storm-related riders filed with the City Council.in 2010.
Gas System Rebuild
In addition to the Hurricane Katrina storm restoration costs that Entergy New Orleans incurred, Entergy New Orleans expects that over a longer term rebuilding of the gas system in New Orleans will be necessary due to the massive salt water intrusion into the system caused by the flooding in New Orleans. The salt water intrusion is expected to shorten the life of the gas system, making it necessary to rebuild portions of that system over time, earlier than otherwise would be expected. Entergy New Orleans currently expects the cost to rebuild the gas system to be $465 million,expected, with the project extending many years into the future. Entergy New Orleans received insurance proceeds for a portion of the estimated future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New Orleans'Orleans’s rate and storm-cost recovery filings requires Entergy New Orleans to record those proceeds in a designated sub-account of other deferred credits until the proceeds are spent on the rebuild project. This other deferred credit is shown as "Gas“Gas system rebuild insurance proceeds"proceeds” on Entergy New Orleans'Orleans’s balance sheet.
Bankruptcy Proceedings
As a result of the effects of Hurricane Katrina and the effect of extensive flooding that resulted from levee breaks in and around the New Orleans area, on September 23, 2005, Entergy New Orleans filed a voluntary petition in bankruptcy court seeking reorganization relief under Chapter 11 of the U.S. Bankruptcy Code. On May 7, 2007, the bankruptcy judge entered an order confirming Entergy New Orleans'Orleans’s plan of reorganization. With the receipt of CDBG funds, and the agreement on insurance recovery with one of its excess insurers, Entergy New Orleans waived the conditions precedent in its plan of reorganization, and the plan became effective on May 8, 2007. Following are significantIncluded in the terms in Entergy New Orleans'the plan of reorganization:
· | Entergy New Orleans paid in full, in cash, the allowed third-party prepetition accounts payable (approximately $29 million, including interest). Entergy New Orleans paid interest from September 23, 2005 at the Louisiana judicial rate of interest for 2005 (6%) and 2006 (8%), and at the Louisiana judicial rate of interest (9.5%) plus 1% for 2007 through the date of payment. |
· | Entergy New Orleans issued notes due in three years in satisfaction of its affiliate prepetition accounts payable (approximately $74 million, including interest), including its indebtedness to the Entergy System money pool. Entergy New Orleans included in the principal amount of the notes accrued interest from September 23, 2005 at the Louisiana judicial rate of interest for 2005 (6%) and 2006 (8%), and at the Louisiana judicial rate of interest plus 1% for 2007 through the date of issuance of the notes. Entergy New Orleans will pay interest on the notes from their date of issuance at the Louisiana judicial rate of interest plus 1%. The Louisiana judicial rate of interest is 9.5% for 2007, 8.5% for 2008, 5.5% for 2009, and 3.5% for 2010. |
reorganization Entergy New Orleans Inc.
Management's Financial Discussion and Analysis
· | Entergy New Orleans repaid in full, in cash, the outstanding borrowings under the debtor-in-possession credit agreement between Entergy New Orleans and Entergy Corporation (approximately $67 million). |
· | Entergy New Orleans' first mortgage bonds remain outstanding with their stated maturity dates and interest terms. Pursuant to an agreement with its first mortgage bondholders, Entergy New Orleans paid the first mortgage bondholders an amount equal to the one year of interest from the bankruptcy petition date that the bondholders had waived previously in the bankruptcy proceeding (approximately $12 million). |
· | Entergy New Orleans' preferred stock remains outstanding on its stated dividend terms, and Entergy New Orleans paid its unpaid preferred dividends in arrears (approximately $1 million). |
· | Litigation claims were generally unaltered, and are generally proceeding as if Entergy New Orleans had not filed for bankruptcy protection, with exceptions for certain claims. |
issued notes to affiliates. Entergy New Orleans repaid, at maturity in May 2010, these notes that represented affiliate prepetition accounts payable (approximately $74 million, including interest), including its indebtedness to the Entergy System money pool.
Liquidity and Capital Resources
Debtor-in-Possession Credit Facility
On September 26, 2005, Entergy New Orleans, as borrower, and Entergy Corporation, as lender, entered into a debtor-in-possession credit facility to provide funding to Entergy New Orleans during its business restoration efforts. The credit facility provided for up to $200 million in loans. The interest rate on borrowings under the credit facility was the average interest rate of borrowings outstanding under Entergy Corporation's revolving credit facility. With the confirmation of Entergy New Orleans' plan of reorganization in May 2007, Entergy New Orleans repaid to Entergy Corporation, in full, in cash, the $67 million of outstanding borrowings under the debtor-in-possession credit facility.
Cash Flow
Cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2012 | | | 2011 | | | 2010 | |
| | | | 2009 | | 2008 | | 2007 | | (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | | $137,444 | | $92,010 | | $17,093 | | $ | 9,834 | | | $ | 54,986 | | | $ | 191,191 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | |
| | Operating activities | | 148,556 | | 87,182 | | 207,394 | |
| | Investing activities | | (59,848) | | (9,777) | | (78,441) | |
| | Financing activities | | (34,961) | | (31,971) | | (54,036) | |
| | Net increase in cash and cash equivalents | | 53,747 | | 45,434 | | 74,917 | |
| Net cash provided by (used in): | | | | | | | | | | | | | |
| Operating activities | | | | 52,089 | | | | 44,927 | | | | 48,965 | |
| Investing activities | | | | (78,040 | ) | | | (46,019 | ) | | | (31,561 | ) |
| Financing activities | | | | 25,508 | | | | (44,060 | ) | | | (153,609 | ) |
| Net decrease in cash and cash equivalents | | | | (443 | ) | | | (45,152 | ) | | | (136,205 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | | $191,191 | | $137,444 | | $92,010 | | $ | 9,391 | | | $ | 9,834 | | | $ | 54,986 | |
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Operating Activities
Net cash provided by operating activities increased $7.2 million in 2012 primarily due to income tax refunds of $13 million in 2012 compared to income tax payments of $39.4 million in 2011 and a decrease of $6.3 million in pension contributions offset by Hurricane Isaac storm restoration spending in 2012, the timing of collections of customer receivables and the decreased recovery of fuel costs. The income tax refunds of $13 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Net cash provided by operating activities increased $61.4 millionwas relatively flat in 2009 primarily due to:
· | the timing of collection of receivables from customers; |
· | income tax refunds of $22.1 million in 2009 compared to income tax payments of $5.8 million in 2008; and |
· | increased recovery of deferred fuel costs. |
The increase was partially offset by the timing of payments to vendors.
Net cash provided by operating activities decreased $120.2 million in 2008 primarily due to2011 as the receipt of $180.8$19.2 million of CBDGCommunity Development Block Grant funds in 2007. This decrease2010 related to Hurricane Katrina costs was partially offset by a decrease of $43.6$28.8 million in pension contributionsincome tax payments in 2011. The decrease in income tax payments is in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The decrease results from lower 2010 taxable income from what was estimated due to revised bonus depreciation deduction and additional repair expenses for tax purposes associated with the timing of payments to vendors.tax accounting method change filed in 2010.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Investing Activities
Net cash used in investing activities increased $50.1$32.0 million in 20092012 primarily due to a decrease in Hurricane Katrina insurance proceeds received in 2009 as compared to 2008,to:
| · | higher distribution construction expenditures due to Hurricane Isaac; |
| · | money pool activity; and |
| · | the repayment by System Fuels of Entergy New Orleans’s $3.3 million investment in System Fuels in 2011. |
The increase was partially offset by net receipts from the storm restoration spendingescrow account of $1.4 million in 2008 related2012 compared to Hurricane Gustav.net payments to the storm escrow account of $6.0 million in 2011.
Decreases in Entergy New Orleans’s receivable from the money pool are a source of cash flow, and Entergy New Orleans’s receivable from the money pool decreased $6.2 million in 2012 compared to decreasing $12.7 million in 2011. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ need for external short-term borrowings.
Net cash used in investing activities decreased $68.7increased $14.5 million in 20082011 primarily due to an increase in Hurricane Katrina insurance proceeds in 2008 as compared to 2007 and money pool activity and a withdrawal in 2010 from the storm escrow account related to Hurricane Gustav costs. The increase was partially offset by proceedsa decrease in construction expenditures due to decreased spending on the gas system rebuild project and System Fuels repayment of $10Entergy New Orleans’s $3.3 million related to the sale of a power plantinvestment in 2007.System Fuels.
IncreasesDecreases in Entergy New Orleans'Orleans’s receivable from the money pool are a usesource of cash flow, and Entergy New Orleans'Orleans’s receivable from the money pool increased by $12.4decreased $12.7 million in 2008. The money pool is an inter-company borrowing arrangement designed2011 compared to reduce Entergy's subsidiaries' need for external short-term borrowings.decreasing $44.3 million in 2010.
Financing Activities
Net cash used inEntergy New Orleans’s financing activities increased $3.0provided $25.5 million in 2012 compared to using $44.1 million in 2011 primarily due to $32.9a decrease of $40.3 million ofin common stock dividends paid on common stock in 2009, partially offset byand the redemption, at maturity,issuance of $30 million of 3.875%5.0% Series First Mortgage Bondsfirst mortgage bonds in August 2008.November 2012.
Net cash used in financing activities decreased $22.1$109.5 million in 2011 primarily due to the repayment in 2010 of $74.3 million of affiliate notes payable that were issued to affiliates as part of Entergy New Orleans' borrowings underOrleans’s plan of reorganization, the debtor-in-possession credit facility in 2007, partially offset by the redemption,repayment, at maturity, of $30 million of 3.875%4.98% Series First Mortgage Bondsfirst mortgage bonds in August 2008.July 2010, and the repayment of $25 million of 6.75% Series first mortgage bonds in December 2010, offset by the issuance of $25 million of 5.10% Series first mortgage bonds in November 2010.
See Note 5 to the financial statements for details on long-term debt.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans'Orleans’s capitalization is balanced between equity and debt as shown in the following table.
| | | December 31, 2009 | | December 31, 2008 | | December 31, 2012 | | December 31, 2011 |
| | | | | | | | | |
| Debt to capital | | | 47.7% | | 45.3% |
| Effect of subtracting cash | | | (1.2%) | | (1.5%) |
| Net debt to net capital | | 26.2% | | 37.0% | | 46.5% | | 43.8% |
| Effect of subtracting cash from debt | | 28.2% | | 17.1% | |
| Debt to capital | | 54.4% | | 54.1% | |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion. Capital consists of debt and shareholders' equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans'Orleans’s financial condition.
Uses of Capital
Entergy New Orleans requires capital resources for:
| · | construction and other capital investments; |
| · | working capital purposes, including the financing of fuel and purchased power costs; |
| · | debt and preferred stock maturities or retirements; and |
Following are the amounts of Entergy New Orleans'Orleans’s planned construction and other capital investments and existing debt and lease obligations (includes estimated interest payments):.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
| | 2010 | | 2011-2012 | | 2013-2014 | | After 2014 | | Total | 2013 | | 2014-2015 | | 2016-2017 | | After 2017 | | Total |
| | (In Millions) | (In Millions) |
| Planned construction and | | | | | | | | | | |
| capital investment (1) | $86 | | $67 | | N/A | | N/A | | $153 | |
| Planned construction and capital investment (1): | | Planned construction and capital investment (1): | | | | | | | |
| Generation | | $19 | | $55 | | N/A | | N/A | | $74 |
| Transmission | | 19 | | 17 | | N/A | | N/A | | 36 |
| Distribution | | 32 | | 57 | | N/A | | N/A | | 89 |
| Other | | 24 | | 48 | | N/A | | N/A | | 72 |
| Total | | $94 | | $177 | | N/A | | N/A | | $271 |
| Long-term debt (2) | $40 | | $19 | | $84 | | $153 | | $296 | $79 | | $14 | | $14 | | $220 | | $327 |
| Operating leases | $1 | | $1 | | $- | | $1 | | $3 | $2 | | $4 | | $3 | | $2 | | $11 |
| Purchase obligations (3) | $174 | | $354 | | $322 | | $1,870 | | $2,720 | $177 | | $335 | | $332 | | $1,593 | | $2,437 |
| (1) | Includes approximately $35$47 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. Also includes spending for the long-term gas rebuild project. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy New Orleans, almost all of the total consists of unconditional fuel and purchased power obligations, including its obligations under the Unit Power Sales Agreement, which is discussed in Note 8 to the financial statements. |
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
In addition to the contractual obligations given above, Entergy New Orleans expects to make payments of approximately $59 million for the years 2010-2012 related to Hurricane Katrina restoration work and its gas rebuild project, of which $34 million is expected to be incurred in 2010. Also, Entergy New Orleanscurrently expects to contribute approximately $5.1$4 million to its pension plan and approximately $5.2$3.7 million to its other postretirement plans in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. 2013. See "Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits" below for a discussion of qualified pension and other postretirement benefits funding.
Also guidance pursuantin addition to the Pension Protection Actcontractual obligations, Entergy New Orleans has $16.5 million of 2006 rules,unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changessettlement of tax positions. See Note 3 to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy New Orleans’ pension contributions in the future.financial statements for additional information regarding unrecognized tax benefits.
The planned capital investment estimate for Entergy New Orleans reflects capital required to support existing business. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in Notes 5 and 6 and to the financial statements.
As an indirect, wholly-owned subsidiary of Entergy Corporation, Entergy New Orleans pays dividends from its earnings at a percentage determined monthly. Entergy New Orleans’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred stock.
Sources of Capital
Entergy New Orleans'Orleans’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt and preferred stock issuances. |
Entergy New Orleans may refinance, redeem, or redeemotherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Entergy New Orleans'Orleans’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:years.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $66,149 | | $60,093 | | 47,705 | | ($37,166) |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $2,923 | | $9,074 | | $21,820 | | $66,149 |
See Note 4 to the financial statements for a description of the money pool. As discussed above in "Bankruptcy Proceedings", in 2007,
Entergy New Orleans issued notes duehas a credit facility in 2010the amount of $25 million scheduled to satisfy its affiliate prepetition accounts payable, including its prepetition indebtednessexpire in November 2013. No borrowings were outstanding under the facility as of December 31, 2012. See Note 4 to the Entergy System money poolfinancial statements for additional discussion of $37.2 million.the credit facility.
Entergy New Orleans has obtained short-term borrowing authorization from the FERC under which it may borrow through October 2011,2013, up to the aggregate amount, at any one time outstanding, of $100 million. See Note 4 to the financial statements for further discussion of Entergy New Orleans'Orleans’s short-term borrowing limits. The long-term securities issuances of Entergy New Orleans are limited to amounts authorized by the City Council, and the current authorization extends through August 2010.July 2014.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Entergy Louisiana’s Ninemile Point Unit 6 Self-Build Project
In June 2011, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by Entergy Louisiana’s construction of a combined-cycle gas turbine generating facility (Ninemile 6) at its existing Ninemile Point electric generating station. Ninemile 6 will be a nominally-sized 550 MW unit that is estimated to cost approximately $721 million to construct, excluding interconnection and transmission upgrades. Entergy Gulf States Louisiana joined in the application, seeking certification of its purchase under a life-of-unit power purchase agreement of up to 35% of the capacity and energy generated by Ninemile 6. The Ninemile 6 capacity and energy is proposed to be allocated 55% to Entergy Louisiana, 25% to Entergy Gulf States Louisiana, and 20% to Entergy New Orleans. In February 2012 the City Council passed a resolution authorizing Entergy New Orleans to purchase 20% of the Ninemile 6 energy and capacity. Entergy New Orleans is expected to file a full rate case 12 months prior to the expected in-service date. In March 2012 the LPSC unanimously voted to grant the certifications requested by Entergy Gulf States Louisiana and Entergy Louisiana. Following approval by the LPSC, Entergy Louisiana issued full notice to proceed to the project’s engineering, procurement, and construction contractor. All major permits and approvals required to begin construction have been obtained and construction is in progress.
State and Local Rate Regulation
The rates that Entergy New Orleans charges for electricity and natural gas significantly influence its financial position, results of operations, and liquidity. Entergy New Orleans is regulated and the rates charged to its customers are determined in regulatory proceedings. A governmental agency, the City Council, is primarily responsible for approval of the rates charged to customers.
Rate Cases, Formula Rate Plans and Storm-related Riders
On July 31, 2008, Entergy New Orleans filed an electric and gas base rate case with the City Council. OnIn April 2, 2009, the City Council approved a comprehensive settlement. The settlement provided for a net $35.3 million reduction in combined fuel and non-fuel electric revenue requirement, including conversion of the $10.6 million voluntary recovery credit to a permanent reduction and substantial realignment of Grand Gulf cost recovery from fuel to electric base rates, and a $4.95 million gas base rate increase, both effective June 1, 2009, with adjustment of the customer charges for all rate classes. A new three-year formula rate plan was also adopted,for Entergy New Orleans, with terms including an 11.1% benchmark electric return on common equity (ROE) with a +/- 40 basis point bandwidth and a 10.75% benchmark gas ROE with a +/- 50 basis point bandwidth. Earnings outside the bandwidth reset to the midpoint benchmark ROE, with rates changing on a prospective basis depending on whether Entergy New Orleans iswas over- or under-earning. The formula rate plan also includesincluded a recovery mechanism for City Council-approved capacity additions, plus provisions for extraordinary cost changes and force majeure events.
In May 2010, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports. The filings requested a $12.8 million electric base revenue decrease and a $2.4 million gas base revenue increase. Entergy New Orleans and the City Council's Advisors reached a settlement that resulted in an $18.0 million electric base revenue decrease and zero gas base revenue change effective with the October 2010 billing cycle. The City Council approved the settlement in November 2010.
In May 2011, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2010 test year. The filings requested a $6.5 million electric rate decrease and a $1.1 million gas rate decrease. Entergy New Orleans and the City Council’s Advisors reached a settlement that results in an $8.5 million incremental electric rate decrease and a $1.6 million gas rate decrease. The settlement also provides for the deferral of $13.4 million of Michoud plant maintenance expenses incurred in 2010 and the establishment of a regulatory asset that will be amortized over the period October 2011 through September 2018. The City Council approved the settlement in September 2011. The new rates were effective with the first billing cycle of October 2011.
In May 2012, Entergy New Orleans filed its electric and gas formula rate plan evaluation reports for the 2011 test year. Subsequent adjustments agreed upon with the City Council Advisors indicate a $4.9 million electric base revenue increase and a $0.05 million gas base revenue increase as necessary under the formula rate plan. As part of the original filing, Entergy New Orleans is also requesting to increase annual funding for its storm reserve by approximately $5.7 million for the next five years. On September 26, 2012, Entergy New Orleans made a filing with the City Council that implemented the $4.9 million electric formula rate plan rate increase and the $0.05 million gas formula rate plan rate increase. The new rates were effective with the first billing cycle in October
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
2012. The new rates have not affected the net amount of Entergy New Orleans’s operating revenues. In October 2012 the City Council approved a procedural schedule to resolve disputed items that includes a hearing in April 2013. The rates implemented in October 2012 are subject to retroactive adjustments depending on the outcome of the proceeding. The City Council has not yet acted on Entergy New Orleans’s request for an increase in storm reserve funding. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not yet been extended. Entergy New Orleans is expected to file a full rate case 12 months prior to the anticipated completion of the Ninemile 6 generating facility.
A 2008 rate case settlement also included $3.1 million per year in electric rates to fund the Energy Smart energy efficiency programs. In September 2009 the City Council approved the energy efficiency programs filed by Entergy New Orleans. The rate settlement provides an incentive for Entergy New Orleans to meet or exceed energy savings targets set by the City Council and provides a mechanism for Entergy New Orleans to recover lost contribution to fixed costs associated with the energy savings generated from the energy efficiency programs. The programs are expected to begin in 2010.
In June 2006, Entergy New Orleans made its annual formula rate plan filings with the City Council. The filings presented various alternatives to reflect the effect of Entergy New Orleans' lost customers and decreased revenue following Hurricane Katrina. The alternative that Entergy New Orleans recommended adjusts for lost customers and assumes that the City Council's June 2006 decision to allow recovery of all Grand Gulf costs through the fuel adjustment clause stays in place during the rate-effective period (a significant portion of Grand Gulf costs was previously recovered through base rates).
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
At the same time as it made its formula rate plan filings, Entergy New Orleans also filed with the City Council a request to implement two storm-related riders. With the first rider, Entergy New Orleans sought to recover the electric and gas restoration costs that it had actually spent through March 31, 2006. Entergy New Orleans also proposed semiannual filings to update the rider for additional restoration spending and also to consider the receipt of CDBG funds or insurance proceeds that it may receive. With the second rider, Entergy New Orleans sought to establish a storm reserve to provide for the risk of another storm.
In October 2006, the City Council approved a rate filing settlement agreement that, resolved Entergy New Orleans' rate and storm-related rider filings by providing for phased-in rate increases, while taking into account with respect to storm restoration costs the anticipated receipt of CDBG funding as recommended by the Louisiana Recovery Authority. The settlement provided for a 0% increase in electric base rates through December 2007, with a $3.9 million increase implemented in January 2008. Recovery of all Grand Gulf costs through the fuel adjustment clause was continued. Gas base rates increased by $4.75 million in November 2006 and increased by an additional $1.5 million in March 2007 and an additional $4.75 million in November 2007. The settlement called for Entergy New Orleans to file a base rate case by July 31, 2008, which it did as discussed above. The settlement agreement discontinued the formula rate plan and the generation performance-based plan but permitted Entergy New Orleans to file an application to seek authority to implement formula rate plan mechanisms no sooner than six months following the effective date of the implementation of the base rates resulting from the July 31, 2008 base rate case. The settlement alsoamong other things, authorized a $75 million storm reserve for damage from future storms, which will be created over a ten-year period through a storm reserve rider beginningthat began in March 2007. These storm reserve funds will beare held in a restricted escrow account.
account until needed in response to a storm. In January 2008,November 2012, Entergy New Orleans voluntarily implemented a 6.15% base rate credit (the recovery credit) for electric customers, which returned approximately $11.3withdrew $10 million to electric customers in 2008. Entergy New Orleans was able to implement this credit because during 2007 the recovery of New Orleans after Hurricane Katrina was occurring faster than expected in 2006 projections. In addition, Entergy New Orleans committed to set aside $2.5 million for an energy efficiency program focused on community education and outreach and weatherization of homes.
In addition to rate proceedings, Entergy New Orleans' fuel costs recovered from customers are subject to regulatory scrutiny. Entergy New Orleans' electric rate schedules include a fuel adjustment tariff designed to reflect no more than targeted fuel and purchased power costs, adjusted by a surcharge or credit for deferred fuel expense arising from the monthly reconciliation of actual fuel and purchased powerstorm reserve escrow account to partially offset the costs incurredassociated with fuel cost revenues billed to customers, including carrying charges. In June 2006 the City Council authorized the recovery of all Grand Gulf costs through Entergy New Orleans' fuel adjustment clause (a significant portion of Grand Gulf costs was previously recovered through base rates), and continued that authorization in approving the October 2006 formula rate plan filing settlement. Effective June 2009, the majority of Grand Gulf costs were realigned to base rates and are no longer flowed through the fuel adjustment clause.
Entergy New Orleans' gas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the billing month, adjusted by a surcharge or credit similar to that included in the electric fuel adjustment clause, including carrying charges. In October 2005, the City Council approved modification of the gas cost collection mechanism effective November 2005 in order to address concerns regarding its fluctuations, particularly during the winter heating season. The modifications are intended to minimize fluctuations in gas rates during the winter months.Hurricane Isaac.
Federal Regulation
System Agreement Proceedings
See "“Independent Coordinator of Transmission”, “System Agreement Proceedings"”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries Management’s Financial Discussion and Analysis for a discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.these topics.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Transmission
See "Independent Coordinator of Transmission" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for further discussion.
Environmental Risks
Entergy New Orleans'Orleans’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous solid wastes, and other environmental matters. Management believes that Entergy New Orleans is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Critical Accounting Estimates
The preparation of Entergy New Orleans'Orleans’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of Entergy New Orleans'Orleans’s financial position or results of operations.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy New Orleans records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month, including fuel price.month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each, period and fuel price fluctuations, in addition to changes in certain components of the calculation. Effective June 2009,
Entergy New Orleans, reclassified the fuel component of unbilled accounts receivable to deferred fuelInc.
Management’s Financial Discussion and will no longer include the fuel component in the unbilled calculation, which is in accordance with regulatory treatment.Analysis
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Entergy New Orleans, Inc.
Management's Financial Discussion and Analysis
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $272 | | $2,903 | | (0.25%) | | $485 | | $6,298 |
| Rate of return on plan assets | | (0.25%) | | $214 | | - | | (0.25%) | | $261 | | $- |
| Rate of increase in compensation | | 0.25% | | $133 | | $675 | | 0.25% | | $194 | | $1,175 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $190 | | $2,303 |
| Health care cost trend | | 0.25% | | $221 | | $1,184 | | 0.25% | | $341 | | $2,019 |
| Discount rate | | (0.25%) | | $110 | | $1,429 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy New Orleans in 20092012 was $1.7$8.5 million. Entergy New Orleans anticipates 20102013 qualified pension cost to be $3.6$9.7 million. Entergy New Orleans contributed $1.1$5.8 million in qualified pension contributions in 20092012 and anticipates approximately a $5.1$4 million pension contribution in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy New Orleans’ pension contributions in the future.2013.
Total postretirement health care and life insurance benefit costs for Entergy New Orleans in 20092012 were $5.9$4.2 million, including $1 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy New Orleans expects 20102013 postretirement health care and life insurance benefit costs to approximate $5.2$2.3 million, including $1.1$1 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy New Orleans expects to contribute approximately $5.2contributed $4.4 million to its other postretirement plans in 2010.2012 and expects to contribute approximately $3.7 million in 2013.
Entergy New Orleans, Inc.
Management’s Financial Discussion and Analysis
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of new accounting pronouncements.Analysis.
To the Board of Directors and Shareholders of
Entergy New Orleans, Inc.
New Orleans, Louisiana
We have audited the accompanying balance sheets of Entergy New Orleans, Inc. (the “Company”) as of December 31, 20092012 and 2008,2011, and the related income statements, statements of income, retained earnings, and cash flows, and statements of changes in common equity (pages 354372 through 358376 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of Entergy New Orleans, Inc. as of December 31, 20092012 and 2008,2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 487,633 | | | $ | 529,228 | | | $ | 543,102 | |
| Natural gas | | | 82,107 | | | | 100,957 | | | | 116,347 | |
| TOTAL | | | 569,740 | | | | 630,185 | | | | 659,449 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 107,616 | | | | 173,668 | | | | 169,644 | |
| Purchased power | | | 222,193 | | | | 207,604 | | | | 218,025 | |
| Other operation and maintenance | | | 122,143 | | | | 106,817 | | | | 130,917 | |
| Taxes other than income taxes | | | 43,189 | | | | 42,032 | | | | 44,749 | |
| Depreciation and amortization | | | 36,726 | | | | 35,026 | | | | 35,354 | |
| Other regulatory charges (credits) - net | | | 1,983 | | | | 1,910 | | | | (1,072 | ) |
| TOTAL | | | 533,850 | | | | 567,057 | | | | 597,617 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 35,890 | | | | 63,128 | | | | 61,832 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 791 | | | | 622 | | | | 667 | |
| Interest and investment income | | | 47 | | | | 154 | | | | 544 | |
| Miscellaneous - net | | | (1,453 | ) | | | (1,234 | ) | | | (2,478 | ) |
| TOTAL | | | (615 | ) | | | (458 | ) | | | (1,267 | ) |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 11,344 | | | | 11,114 | | | | 13,170 | |
| Allowance for borrowed funds used during construction | | | (374 | ) | | | (282 | ) | | | (320 | ) |
| TOTAL | | | 10,970 | | | | 10,832 | | | | 12,850 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 24,305 | | | | 51,838 | | | | 47,715 | |
| | | | | | | | | | | | | |
| Income taxes | | | 7,240 | | | | 15,862 | | | | 16,601 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 17,065 | | | | 35,976 | | | | 31,114 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 965 | | | | 965 | | | | 965 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 16,100 | | | $ | 35,011 | | | $ | 30,149 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 17,065 | | | $ | 35,976 | | | $ | 31,114 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Depreciation and amortization | | | 36,726 | | | | 35,026 | | | | 35,354 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 15,016 | | | | (35,276 | ) | | | (47,611 | ) |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | (29,046 | ) | | | 24,275 | | | | (6,289 | ) |
| Fuel inventory | | | 2,029 | | | | (1,160 | ) | | | (113 | ) |
| Accounts payable | | | 4,828 | | | | (3,502 | ) | | | 3,307 | |
| Prepaid taxes | | | (1,377 | ) | | | - | | | | - | |
| Interest accrued | | | 180 | | | | 12 | | | | (1,121 | ) |
| Deferred fuel costs | | | (9,464 | ) | | | 4,694 | | | | 10,923 | |
| Other working capital accounts | | | 14,239 | | | | (7,764 | ) | | | 4,174 | |
| Provisions for estimated losses | | | (812 | ) | | | 4,637 | | | | (4,785 | ) |
| Other regulatory assets | | | (23,188 | ) | | | (42,667 | ) | | | (10,073 | ) |
| Pension and other postretirement liabilities | | | 9,773 | | | | 25,202 | | | | 5,042 | |
| Other assets and liabilities | | | 16,120 | | | | 5,474 | | | | 29,043 | |
| Net cash flow provided by operating activities | | | 52,089 | | | | 44,927 | | | | 48,965 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (86,373 | ) | | | (56,600 | ) | | | (80,218 | ) |
| Allowance for equity funds used during construction | | | 791 | | | | 622 | | | | 667 | |
| Insurance proceeds | | | - | | | | - | | | | 115 | |
| Investments in affiliates | | | - | | | | 3,256 | | | | - | |
| Change in money pool receivable - net | | | 6,151 | | | | 12,746 | | | | 44,329 | |
| Payments to storm reserve escrow account | | | (8,609 | ) | | | (6,043 | ) | | | - | |
| Receipts from storm resrve escrow account | | | 10,000 | | | | - | | | | 3,546 | |
| Net cash flow used in investing activities | | | (78,040 | ) | | | (46,019 | ) | | | (31,561 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 28,422 | | | | - | | | | 24,349 | |
| Retirement of long-term debt | | | - | | | | - | | | | (129,993 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (1,700 | ) | | | (42,000 | ) | | | (47,000 | ) |
| Preferred stock | | | (965 | ) | | | (965 | ) | | | (965 | ) |
| Other | | | (249 | ) | | | (1,095 | ) | | | - | |
| Net cash flow provided by (used in) financing activities | | | 25,508 | | | | (44,060 | ) | | | (153,609 | ) |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (443 | ) | | | (45,152 | ) | | | (136,205 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 9,834 | | | | 54,986 | | | | 191,191 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 9,391 | | | $ | 9,834 | | | $ | 54,986 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 10,183 | | | $ | 10,109 | | | $ | 13,550 | |
| Income taxes | | $ | (12,952 | ) | | $ | 39,403 | | | $ | 68,160 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents | | | | | | |
| Cash | | $ | 319 | | | $ | 486 | |
| Temporary cash investments | | | 9,072 | | | | 9,348 | |
| Total cash and cash equivalents | | | 9,391 | | | | 9,834 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 33,142 | | | | 29,038 | |
| Allowance for doubtful accounts | | | (446 | ) | | | (465 | ) |
| Associated companies | | | 29,326 | | | | 12,167 | |
| Other | | | 3,115 | | | | 2,603 | |
| Accrued unbilled revenues | | | 18,124 | | | | 17,023 | |
| Total accounts receivable | | | 83,261 | | | | 60,366 | |
| Accumulated deferred income taxes | | | 9,517 | | | | 6,419 | |
| Fuel inventory - at average cost | | | 1,777 | | | | 3,806 | |
| Materials and supplies - at average cost | | | 10,889 | | | | 9,392 | |
| Prepaid taxes | | | 1,377 | | | | - | |
| Prepayments and other | | | 3,201 | | | | 2,679 | |
| TOTAL | | | 119,413 | | | | 92,496 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Non-utility property at cost (less accumulated depreciation) | | | 1,016 | | | | 1,016 | |
| Storm reserve escrow account | | | 10,605 | | | | 11,996 | |
| TOTAL | | | 11,621 | | | | 13,012 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 860,358 | | | | 812,329 | |
| Natural gas | | | 217,769 | | | | 213,160 | |
| Construction work in progress | | | 11,135 | | | | 13,610 | |
| TOTAL UTILITY PLANT | | | 1,089,262 | | | | 1,039,099 | |
| Less - accumulated depreciation and amortization | | | 549,587 | | | | 525,621 | |
| UTILITY PLANT - NET | | | 539,675 | | | | 513,478 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Deferred fuel costs | | | 4,080 | | | | 4,080 | |
| Other regulatory assets | | | 202,003 | | | | 178,815 | |
| Other | | | 4,997 | | | | 4,154 | |
| TOTAL | | | 211,080 | | | | 187,049 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 881,789 | | | $ | 806,035 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 70,000 | | | $ | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 28,778 | | | | 27,042 | |
| Other | | | 31,209 | | | | 28,098 | |
| Customer deposits | | | 21,974 | | | | 21,878 | |
| Interest accrued | | | 3,020 | | | | 2,840 | |
| Deferred fuel costs | | | 2,157 | | | | 11,621 | |
| System agreement cost equalization | | | 16,880 | | | | - | |
| Other | | | 3,479 | | | | 4,197 | |
| TOTAL CURRENT LIABILITIES | | | 177,497 | | | | 95,676 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 172,790 | | | | 144,405 | |
| Accumulated deferred investment tax credits | | | 1,300 | | | | 1,539 | |
| Regulatory liability for income taxes - net | | | 24,291 | | | | 33,258 | |
| Other regulatory liabilities | | | 11,060 | | | | 5,726 | |
| Asset retirement cost liabilities | | | 2,193 | | | | 2,893 | |
| Accumulated provisions | | | 15,031 | | | | 15,843 | |
| Pension and other postretirement liabilities | | | 83,790 | | | | 74,017 | |
| Long-term debt | | | 126,300 | | | | 166,537 | |
| Gas system rebuild insurance proceeds | | | 44,207 | | | | 55,707 | |
| Other | | | 7,985 | | | | 9,489 | |
| TOTAL NON-CURRENT LIABILITIES | | | 488,947 | | | | 509,414 | |
| | | | | | | | | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 19,780 | | | | 19,780 | |
| | | | | | | | | |
| COMMON EQUITY | | | | | | | | |
| Common stock, $4 par value, authorized 10,000,000 | | | | | | | | |
| shares; issued and outstanding 8,435,900 shares in 2012 | | | | | | | | |
| and 2011 | | | 33,744 | | | | 33,744 | |
| Paid-in capital | | | 36,294 | | | | 36,294 | |
| Retained earnings | | | 125,527 | | | | 111,127 | |
| TOTAL | | | 195,565 | | | | 181,165 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 881,789 | | | $ | 806,035 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| STATEMENTS OF CHANGES IN COMMON EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | Common Equity | | | | |
| | | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 33,744 | | | $ | 36,294 | | | $ | 134,967 | | | $ | 205,005 | |
| Net income | | | - | | | | - | | | | 31,114 | | | | 31,114 | |
| Common stock dividends | | | - | | | | - | | | | (47,000 | ) | | | (47,000 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (965 | ) | | | (965 | ) |
| Balance at December 31, 2010 | | $ | 33,744 | | | $ | 36,294 | | | $ | 118,116 | | | $ | 188,154 | |
| Net income | | | - | | | | - | | | | 35,976 | | | | 35,976 | |
| Common stock dividends | | | - | | | | - | | | | (42,000 | ) | | | (42,000 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (965 | ) | | | (965 | ) |
| Balance at December 31, 2011 | | $ | 33,744 | | | $ | 36,294 | | | $ | 111,127 | | | $ | 181,165 | |
| Net income | | | - | | | | - | | | | 17,065 | | | | 17,065 | |
| Common stock dividends | | | - | | | | - | | | | (1,700 | ) | | | (1,700 | ) |
| Preferred stock dividends | | | - | | | | - | | | | (965 | ) | | | (965 | ) |
| Balance at December 31, 2012 | | $ | 33,744 | | | $ | 36,294 | | | $ | 125,527 | | | $ | 195,565 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 535,985 | | | $ | 672,940 | | | $ | 557,458 | |
| Natural gas | | | 104,437 | | | | 141,443 | | | | 119,469 | |
| TOTAL | | | 640,422 | | | | 814,383 | | | | 676,927 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 196,917 | | | | 330,472 | | | | 243,470 | |
| Purchased power | | | 198,836 | | | | 227,065 | | | | 198,329 | |
| Other operation and maintenance | | | 107,803 | | | | 108,576 | | | | 114,254 | |
| Taxes other than income taxes | | | 40,476 | | | | 41,641 | | | | 38,439 | |
| Depreciation and amortization | | | 33,943 | | | | 32,756 | | | | 32,287 | |
| Other regulatory charges - net | | | 1,709 | | | | 4,114 | | | | 4,127 | |
| TOTAL | | | 579,684 | | | | 744,624 | | | | 630,906 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 60,738 | | | | 69,759 | | | | 46,021 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 230 | | | | 602 | | | | 1,736 | |
| Interest and dividend income | | | 3,762 | | | | 9,664 | | | | 11,583 | |
| Miscellaneous - net | | | (1,125 | ) | | | (1,432 | ) | | | (1,057 | ) |
| TOTAL | | | 2,867 | | | | 8,834 | | | | 12,262 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 11,628 | | | | 12,465 | | | | 12,978 | |
| Other interest - net | | | 5,337 | | | | 8,517 | | | | 8,519 | |
| Allowance for borrowed funds used during construction | | | (98 | ) | | | (388 | ) | | | (1,302 | ) |
| TOTAL | | | 16,867 | | | | 20,594 | | | | 20,195 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 46,738 | | | | 57,999 | | | | 38,088 | |
| | | | | | | | | | | | | |
| Income taxes | | | 15,713 | | | | 23,052 | | | | 13,506 | |
| | | | | | | | | | | | | |
| NET INCOME | | | 31,025 | | | | 34,947 | | | | 24,582 | |
| | | | | | | | | | | | | |
| Preferred dividend requirements and other | | | 965 | | | | 965 | | | | 1,126 | |
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO | | | | | | | | | | | | |
| COMMON STOCK | | $ | 30,060 | | | $ | 33,982 | | | $ | 23,456 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 569,740 | | | $ | 630,185 | | | $ | 659,449 | | | $ | 640,422 | | | $ | 814,383 | |
| Net Income | | $ | 17,065 | | | $ | 35,976 | | | $ | 31,114 | | | $ | 30,479 | | | $ | 34,337 | |
| Total assets | | $ | 881,789 | | | $ | 806,035 | | | $ | 850,076 | | | $ | 995,818 | | | $ | 998,460 | |
| Long-term obligations (1) | | $ | 146,080 | | | $ | 186,317 | | | $ | 186,995 | | | $ | 187,803 | | | $ | 292,753 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 174 | | | $ | 176 | | | $ | 196 | | | $ | 168 | | | $ | 172 | |
| Commercial | | | 164 | | | | 154 | | | | 174 | | | | 166 | | | | 194 | |
| Industrial | | | 31 | | | | 30 | | | | 36 | | | | 37 | | | | 48 | |
| Governmental | | | 63 | | | | 59 | | | | 70 | | | | 70 | | | | 79 | |
| Total retail | | | 432 | | | | 419 | | | | 476 | | | | 441 | | | | 493 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 44 | | | | 95 | | | | 56 | | | | 87 | | | | 161 | |
| Non-associated companies | | | - | | | | 1 | | | | 1 | | | | 1 | | | | 2 | |
| Other | | | 12 | | | | 14 | | | | 10 | | | | 7 | | | | 17 | |
| Total | | $ | 488 | | | $ | 529 | | | $ | 543 | | | $ | 536 | | | $ | 673 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 1,772 | | | | 1,888 | | | | 1,858 | | | | 1,577 | | | | 1,394 | |
| Commercial | | | 1,968 | | | | 1,939 | | | | 1,899 | | | | 1,813 | | | | 1,774 | |
| Industrial | | | 484 | | | | 498 | | | | 503 | | | | 526 | | | | 541 | |
| Governmental | | | 785 | | | | 795 | | | | 809 | | | | 805 | | | | 774 | |
| Total retail | | | 5,009 | | | | 5,120 | | | | 5,069 | | | | 4,721 | | | | 4,483 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 978 | | | | 1,167 | | | | 906 | | | | 1,528 | | | | 1,336 | |
| Non-associated companies | | | 8 | | | | 19 | | | | 13 | | | | 15 | | | | 25 | |
| Total | | | 5,995 | | | | 6,306 | | | | 5,988 | | | | 6,264 | | | | 5,844 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 31,025 | | | $ | 34,947 | | | $ | 24,582 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Other regulatory charges - net | | | 1,709 | | | | 4,114 | | | | 4,127 | |
| Depreciation and amortization | | | 33,943 | | | | 32,756 | | | | 32,287 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 54,797 | | | | 3,420 | | | | 30,642 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 19,448 | | | | (7,857 | ) | | | 11,563 | |
| Fuel inventory | | | 5,665 | | | | (3,698 | ) | | | 541 | |
| Accounts payable | | | (3,224 | ) | | | 5,157 | | | | (26,746 | ) |
| Taxes accrued | | | (18,669 | ) | | | 15,365 | | | | 2,895 | |
| Interest accrued | | | 19 | | | | (1,287 | ) | | | (12,787 | ) |
| Deferred fuel costs | | | 13,751 | | | | (4,546 | ) | | | 1,715 | |
| Other working capital accounts | | | 4,131 | | | | (2,009 | ) | | | 9,473 | |
| Provision for estimated losses and reserves | | | 5,382 | | | | (3,720 | ) | | | 5,944 | |
| Changes in other regulatory assets | | | (2,227 | ) | | | (35,134 | ) | | | 181,061 | |
| Changes in pension and other postretirement liabilities | | | (5,549 | ) | | | 33,838 | | | | (44,549 | ) |
| Other | | | 8,355 | | | | 15,836 | | | | (13,354 | ) |
| Net cash flow provided by operating activities | | | 148,556 | | | | 87,182 | | | | 207,394 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (61,954 | ) | | | (103,298 | ) | | | (93,676 | ) |
| Allowance for equity funds used during construction | | | 230 | | | | 602 | | | | 1,736 | |
| Insurance proceeds | | | 14,553 | | | | 102,914 | | | | 56,430 | |
| Proceeds from the sale of assets | | | - | | | | - | | | | 10,046 | |
| Change in money pool receivable - net | | | (6,056 | ) | | | (12,389 | ) | | | (47,705 | ) |
| Changes in other investments - net | | | (6,621 | ) | | | 2,394 | | | | (5,272 | ) |
| Net cash flow used in investing activities | | | (59,848 | ) | | | (9,777 | ) | | | (78,441 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Repayment on DIP credit facility | | | - | | | | - | | | | (51,934 | ) |
| Retirement of long-term debt | | | (728 | ) | | | (30,952 | ) | | | (208 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (32,900 | ) | | | - | | | | - | |
| Preferred stock | | | (965 | ) | | | (965 | ) | | | (1,894 | ) |
| Other | | | (368 | ) | | | (54 | ) | | | - | |
| Net cash flow used in financing activities | | | (34,961 | ) | | | (31,971 | ) | | | (54,036 | ) |
| | | | | | | | | | | | | |
| Net increase in cash and cash equivalents | | | 53,747 | | | | 45,434 | | | | 74,917 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 137,444 | | | | 92,010 | | | | 17,093 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 191,191 | | | $ | 137,444 | | | $ | 92,010 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid/(received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 16,302 | | | $ | 21,557 | | | $ | 24,450 | |
| Income taxes | | $ | (22,054 | ) | | $ | 5,821 | | | $ | (3,571 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents | | | | | | |
| Cash | | $ | 1,179 | | | $ | 1,119 | |
| Temporary cash investments | | | 190,012 | | | | 136,325 | |
| Total cash and cash equivalents | | | 191,191 | | | | 137,444 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 41,284 | | | | 53,934 | |
| Allowance for doubtful accounts | | | (1,166 | ) | | | (1,112 | ) |
| Associated companies | | | 78,670 | | | | 70,608 | |
| Other | | | 2,299 | | | | 3,270 | |
| Accrued unbilled revenues | | | 20,328 | | | | 28,107 | |
| Total accounts receivable | | | 141,415 | | | | 154,807 | |
| Deferred fuel costs | | | 3,996 | | | | 21,827 | |
| Accumulated deferred income taxes | | | 2,584 | | | | - | |
| Fuel inventory - at average cost | | | 2,533 | | | | 8,198 | |
| Materials and supplies - at average cost | | | 9,674 | | | | 9,472 | |
| Prepayments and other | | | 4,311 | | | | 4,483 | |
| TOTAL | | | 355,704 | | | | 336,231 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investment in affiliates - at equity | | | 3,259 | | | | 3,259 | |
| Non-utility property at cost (less accumulated depreciation) | | | 1,016 | | | | 1,016 | |
| Storm reserve escrow account | | | 9,499 | | | | 2,878 | |
| TOTAL | | | 13,774 | | | | 7,153 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 789,367 | | | | 767,327 | |
| Natural gas | | | 199,847 | | | | 197,231 | |
| Construction work in progress | | | 21,148 | | | | 22,314 | |
| TOTAL UTILITY PLANT | | | 1,010,362 | | | | 986,872 | |
| Less - accumulated depreciation and amortization | | | 514,609 | | | | 542,499 | |
| UTILITY PLANT - NET | | | 495,753 | | | | 444,373 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Deferred fuel costs | | | 4,080 | | | | - | |
| Other regulatory assets | | | 125,686 | | | | 208,524 | |
| Other | | | 6,079 | | | | 7,254 | |
| TOTAL | | | 135,845 | | | | 215,778 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 1,001,076 | | | $ | 1,003,535 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. |
| BALANCE SHEETS |
| LIABILITIES AND SHAREHOLDERS' EQUITY |
| | | | | | | | | |
| | | December 31, |
| | | 2009 | | | | 2008 | |
| | | (In Thousands) |
| | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | | $ | 30,000 | | | $ | - | |
| Notes payable - associated companies | | | 74,230 | | | | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 28,138 | | | | 24,523 | |
| Other | | | 23,653 | | | | 39,327 | |
| Customer deposits | | | 20,505 | | | | 18,944 | |
| Taxes accrued | | | 1,677 | | | | 20,346 | |
| Accumulated deferred income taxes | | | - | | | | 7,387 | |
| Interest accrued | | | 3,949 | | | | 3,930 | |
| System agreement cost equalization | | | 6,000 | | | | - | |
| Other | | | 5,803 | | | | 9,203 | |
| TOTAL CURRENT LIABILITIES | | | 193,955 | | | | 123,660 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 147,496 | | | | 112,827 | |
| Accumulated deferred investment tax credits | | | 2,153 | | | | 2,471 | |
| Regulatory liability for income taxes - net | | | 58,970 | | | | 72,046 | |
| Other regulatory liabilities | | | 43,148 | | | | 12,040 | |
| Retirement cost liability | | | 3,174 | | | | 2,966 | |
| Accumulated provisions | | | 15,991 | | | | 10,609 | |
| Pension and other postretirement liabilities | | | 43,773 | | | | 49,322 | |
| Long-term debt | | | 168,023 | | | | 272,973 | |
| Gas system rebuild insurance proceeds | | | 90,116 | | | | 98,418 | |
| Other | | | 5,911 | | | | 14,997 | |
| TOTAL NON-CURRENT LIABILITIES | | | 578,755 | | | | 648,669 | |
| | | | | | | | | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| Preferred stock without sinking fund | | | 19,780 | | | | 19,780 | |
| | | | | | | | | |
| SHAREHOLDERS' EQUITY | | | | | | | | |
| Common stock, $4 par value, authorized 10,000,000 | | | | | | | | |
| shares; issued and outstanding 8,435,900 shares in 2009 | | | | | | | | |
| and 2008 | | | 33,744 | | | | 33,744 | |
| Paid-in capital | | | 36,294 | | | | 36,294 | |
| Retained earnings | | | 138,548 | | | | 141,388 | |
| TOTAL | | | 208,586 | | | | 211,426 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDERS' EQUITY | | $ | 1,001,076 | | | $ | 1,003,535 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| STATEMENTS OF RETAINED EARNINGS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Retained Earnings, January 1 | | $ | 141,388 | | | $ | 107,406 | | | $ | 83,950 | |
| | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | |
| Net income | | | 31,025 | | | | 34,947 | | | | 24,582 | |
| | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | |
| Dividends declared on common stock | | | 32,900 | | | | - | | | | - | |
| Dividends declared on preferred stock | | | 965 | | | | 965 | | | | 1,126 | |
| | | | | | | | | | | | | |
| Retained Earnings, December 31 | | $ | 138,548 | | | $ | 141,388 | | | $ | 107,406 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 640,422 | | | $ | 814,383 | | | $ | 676,927 | | | $ | 571,154 | | | $ | 673,326 | |
| Net Income | | $ | 31,025 | | | $ | 34,947 | | | $ | 24,582 | | | $ | 5,344 | | | $ | 1,250 | |
| Total assets | | $ | 1,001,076 | | | $ | 1,003,535 | | | $ | 876,195 | | | $ | 921,151 | | | $ | 1,120,121 | |
| Long-term obligations (1) | | $ | 168,023 | | | $ | 272,973 | | | $ | 273,912 | | | $ | 229,875 | | | $ | 229,859 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt). | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | |
| | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 168 | | | $ | 172 | | | $ | 142 | | | $ | 106 | | | $ | 150 | |
| Commercial | | | 166 | | | | 194 | | | | 181 | | | | 165 | | | | 145 | |
| Industrial | | | 37 | | | | 48 | | | | 47 | | | | 45 | | | | 32 | |
| Governmental | | | 70 | | | | 79 | | | | 72 | | | | 59 | | | | 59 | |
| Total retail | | | 441 | | | | 493 | | | | 442 | | | | 375 | | | | 386 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 87 | | | | 161 | | | | 103 | | | | 46 | | | | 117 | |
| Non-associated companies | | | 1 | | | | 2 | | | | 1 | | | | 45 | | | | 21 | |
| Other | | | 7 | | | | 17 | | | | 11 | | | | 5 | | | | 12 | |
| Total | | $ | 536 | | | $ | 673 | | | $ | 557 | | | $ | 471 | | | $ | 536 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | | | | |
| Residential | | | 1,577 | | | | 1,394 | | | | 1,221 | | | | 914 | | | | 1,616 | |
| Commercial | | | 1,813 | | | | 1,774 | | | | 1,763 | | | | 1,666 | | | | 1,798 | |
| Industrial | | | 526 | | | | 541 | | | | 568 | | | | 547 | | | | 498 | |
| Governmental | | | 805 | | | | 774 | | | | 747 | | | | 632 | | | | 800 | |
| Total retail | | | 4,721 | | | | 4,483 | | | | 4,299 | | | | 3,759 | | | | 4,712 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 1,528 | | | | 1,336 | | | | 995 | | | | 519 | | | | 1,705 | |
| Non-associated companies | | | 15 | | | | 25 | | | | 15 | | | | 779 | | | | 336 | |
| Total | | | 6,264 | | | | 5,844 | | | | 5,309 | | | | 5,057 | | | | 6,753 | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
ENTERGY TEXAS, INC. AND SUBSIDIARIES
Jurisdictional Separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy TexasPlan to Spin Off the Utility’s Transmission Business
Effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation into two vertically integrated utility companies, one operating underSee the sole retail jurisdiction of“Plan to Spin Off the PUCT, Entergy Texas, and the other operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Management believes that the jurisdictional separation will better align Entergy Gulf States, Inc.'s Louisiana and Texas operations to serve customers in those states and to operate consistent with state-specific regulatory requirements as the utility regulatory environments in those jurisdictions evolve. The jurisdictional separation provides for regulation of each separated company by a single retail regulator, which should reduce regulatory complexity.Utility’s Transmission Business
Entergy Texas now owns all Entergy Gulf States, Inc. distribution and transmission assets located in Texas, the gas-fired generating plants located in Texas, undivided 42.5% ownership shares” section of Entergy Gulf States, Inc.'s 70% ownership interest in Nelson 6Corporation and 42% ownership interest in Big Cajun 2, Unit 3, which are coal-fired generating plants located in Louisiana, and other assets and contract rights to the extent related to utility operations in Texas. Entergy Gulf States Louisiana now owns all of the remaining assets that were owned by Entergy Gulf States, Inc. On a book value basis, approximately 58.1% of the Entergy Gulf States, Inc. assets were allocated to Entergy Gulf States Louisiana and approximately 41.9% were allocated to Entergy Texas.
Entergy Gulf States Louisiana remains primarily liable for all of the long-term debt issued by Entergy Gulf States, Inc. that was outstanding on December 31, 2007. Under a debt assumption agreement with Entergy Gulf States Louisiana, Entergy Texas assumed its pro rata share of this long-term debt, which was $1.079 billion, or approximately 46%, of which $168 million remains outstanding at December 31, 2009. The pro rata share of the long-term debt assumed by Entergy Texas was determined by first determining the net assets for each company on a book value basis, and then calculating a debt assumption ratio that resulted in the common equity ratios for each company being approximately the same as the Entergy Gulf States, Inc. common equity ratio immediately prior to the jurisdictional separation. Entergy Texas' debt assumption does not discharge Entergy Gulf States Louisiana's liability for the long-term debt. To secure its debt assumption obligations, Entergy Texas granted to Entergy Gulf States Louisiana a first lien on Entergy Texas' assets that were previously subject to the Entergy Gulf States, Inc. mortgage. Entergy Texas has until December 31, 2010 to repay the assumed debt. In addition, Entergy Texas, as the owner of Entergy Gulf States Reconstruction Funding I, LLC ("EGSRF I"), will report the $329.5 million of senior secured transition bonds ("securitization bonds") issued by EGSRF I as long-term debt on its consolidated balance sheet. The securitization bonds are non-recourse to Entergy Texas.
Entergy Texas will purchase from Entergy Gulf States Louisiana pursuant to a life-of-unit purchased power agreement (PPA) a 42.5% share of capacity and energy from the 70% of River Bend subject to retail regulation. Entergy Texas was allocated a share of River Bend's nuclear and environmental liabilities that is identical to the share of the plant's output purchased by Entergy Texas under the PPA. Entergy Gulf States Louisiana will purchase a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas will purchase a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Gulf States Louisiana. The PPAs associated with the gas-fired generating plants will terminate when retail open access commences in Entergy Texas' jurisdiction or when the unit(s) is no longer dispatched by the Entergy System. If Entergy Texas implements retail open access, it will terminate its participation in the System Agreement, except for the portion of the System Agreement related to transmission equalization. The dispatch and operation of the generating plants will not change as a result of the jurisdictional separation.
Because the jurisdictional separation was a transaction involving entities under common control, Entergy Texas recognized the assets and liabilities allocated to it at their carrying amounts in the accounts of Entergy Gulf States, Inc. at the time of the jurisdictional separation. Entergy Texas' financial statements report results of operations for 2007 as though the jurisdictional separation had occurred at the beginning of 2007, and presents its 2007 other financial information as of the beginning of 2007 as though the assets and liabilities had been allocated at that date. Financial statements and financial information presented for prior periods have also been presented on that basis to furnish comparative information.
Entergy Texas, Inc.
Management'sSubsidiaries Management’s Financial Discussion and Analysis
for a discussion of Entergy’s plan to spin off its transmission business and merge it with a newly formed subsidiary of ITC Holdings Corp., including the planned retirement of debt.
Results of Operations
Net Income
20092012 Compared to 20082011
Net income increased by $5.9decreased $38.9 million primarily due to higherlower net revenue, and higher other income, partially offset by higher other operation and maintenance expenses, and higher interest and other charges.
2008 Compared to 2007
Net income decreased $1 million primarily due to higher depreciation and amortization expenses, and lower other income, partially offset by lower interesttaxes other than income taxes.
2011 Compared to 2010
Net income increased $14.6 million primarily due to higher net revenue, partially offset by higher taxes other than income taxes, higher other operation and other chargesmaintenance expenses, and a lower effective income tax rate.higher depreciation and amortization expenses.
Net Revenue
20092012 Compared to 20082011
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20092012 to 2008.2011.
| | Amount |
| | (In Millions) |
| | |
2008 net revenue | | $440.9 |
Retail electric price | | 32.1 |
Volume/weather | | 19.0 |
Net wholesale revenue | | 15.0 |
Rough production cost equalization | | (18.6) |
Reserve equalization | | (8.1) |
Other | | 4.8 |
2009 net revenue | | $485.1 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2011 net revenue | | $ | 577.8 | |
| Volume/weather | | | (22.7 | ) |
| Purchased power capacity | | | (20.1 | ) |
| Fuel recovery | | | (6.5 | ) |
| Retail electric price | | | 15.1 | |
| Reserve equalization | | | 20.2 | |
| Other | | | (12.8 | ) |
| 2012 net revenue | | $ | 551.0 | |
The volume/weather variance is primarily due to a decrease of 519 GWh, or 3.1%, in billed electricity usage, including the effect of milder weather compared to last year on residential and commercial sales.
The purchased power capacity variance is primarily due to additional capacity purchases as well as price increases for ongoing purchased power capacity.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The fuel recovery variance is primarily the result of a $6 million adjustment to deferred fuel costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order.
The retail electric price variance is primarily due to rate increases effective late-Januaryactions, including an annual base rate increase of $9 million beginning May 2011 as a result of the settlement of the December 2009 rate case and an Energy Efficiency rider which becameannual base rate increase of $28 million, effective July 2012, as a result of the PUCT’s order in the December 31, 2008, which is substantially offset in other operation and maintenance expenses.2011 rate case. See Note 2 to the financial statements for further discussion of the rate increases.
The volume/weather variance is primarily due to the effect of more favorable weather on billed and unbilled sales in 2009 compared to the same period in 2008 and an increase in unbilled sales volume, including the effects of Hurricane Ike which decreased sales volume in 2008.
The net wholesale revenue variance is primarily due to higher capacity revenue as a result of the purchased power agreements between Entergy Gulf States Louisiana and Entergy Texas and increased volume to municipal and co-op customers.
As discussed further in Note 2 to the financial statements, the rough production cost equalization variance is due to an additional $18.6 million allocation of 2007 rough production cost equalization receipts ordered by the PUCT to Texas retail customers over what was originally allocated to Entergy Texas prior to the jurisdictional separation of Entergy Gulf States, Inc. into Entergy Gulf States Louisiana and Entergy Texas, effective December 2007.cases.
The reserve equalization variance is primarily due to increaseddecreased reserve equalization expense related toas a result of changes in the Entergy System generation mix compared to the same period in 2008.2011.
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges
Gross operating revenues decreased primarily due to a decrease of $285.3to:
| · | a decrease of $156.2 million in fuel cost recovery revenues primarily attributable to lower fuel rates and lower usage, offset by lower interim fuel refunds in 2012 versus 2011. Entergy Texas’s fuel and purchased power recovery mechanism is discussed in Note 2 to the financial statements. The interim fuel refunds and the PUCT approvals are discussed in Note 2 to the financial statements; and |
| · | less favorable volume/weather, as discussed above. |
The decrease was partially offset by an increase of $12.2 million in gross wholesale revenues as a result of an increase in sales to affiliated customers, offset by a decrease in affiliated wholesale revenue of $141.8 million duesales volume to a decrease in the average price of energy available for resale sales.municipal and co-op customers.
Fuel and purchased power expenses decreased primarily due to decreases in the average market prices of natural gas and purchased power, partially offset by an increase in deferred fuel expense. The increase in deferred fuel expense is due to an adjustment to deferred fuel costs in accordance with a rate order from the PUCT issued in September 2012 and purchased power expense decreases in excessas a result of lower interim fuel cost recovery revenues.refunds in 2012 versus 2011, offset by lower fuel revenues, as discussed above. See Note 2 to the financial statements for further discussion of the PUCT rate order.
Other regulatory charges increased primarily due to the distribution in the first quarter 2011 of $17.4 million to customers of the 2007 rough production cost equalization charges as described above.remedy receipts. See Note 2 to the financial statements for further discussion of the rough production cost equalization proceedings.
20082011 Compared to 20072010
Net revenue consists of operating revenues net of: 1) fuel, fuel-related expenses, and gas purchased for resale, 2) purchased power expenses, and 3) other regulatory charges. Following is an analysis of the change in net revenue comparing 20082011 to 2007.2010.
| | Amount |
| | (In Millions) |
| | |
2007 net revenue | | $442.3 |
Volume/weather | | (4.6) |
Reserve equalization | | (3.3) |
Securitization transition charge | | 9.1 |
Fuel recovery | | 7.5 |
Other | | (10.1) |
2008 net revenue | | $440.9 |
| | | Amount | |
| | | (In Millions) | |
| | | | |
| 2010 net revenue | | $ | 540.2 | |
| Retail electric price | | | 36.0 | |
| Volume/weather | | | 21.3 | |
| Purchased power capacity | | | (24.6 | ) |
| Other | | | 4.9 | |
| 2011 net revenue | | $ | 577.8 | |
The retail electric price variance is primarily due to rate actions, including an annual base rate increase of $59 million beginning August 2010, with an additional increase of $9 million beginning May 2011, as a result of the settlement of the December 2009 rate case. See Note 2 to the financial statements for further discussion of the rate case settlement.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The volume/weather variance is primarily due to decreasedan increase of 721 GWh, or 4.5%, in billed electricity usage, duringincluding the unbilledeffect of more favorable weather on residential and commercial sales period. See "Critical Accounting Estimates" belowcompared to last year. Usage in the industrial sector increased 8.2% primarily in the chemicals and Note 1 to the financial statements for further discussion of the accounting for unbilled revenues.refining industries.
The reserve equalizationpurchased power capacity variance is primarily due to lower reserve equalization revenue related to changes in the Entergy System generation mix compared to the same period in 2007.
The securitization transition charge variance is primarily due to the issuance of securitization bonds. In June 2007, Entergy Gulf States Reconstruction Funding I, a company wholly-owned and consolidated by Entergy Texas, issued securitization bonds and with the proceeds purchased from Entergy Texas the transition property, which is the right to recover from customers through a transition charge amounts sufficient to service the securitization bonds. See Note 5 to the financial statementsprice increases for additional information regarding the securitization bonds.
The fuel recovery variance is primarily due to a reserve for potential rate refunds made in the first quarter 2007 as a result of a PUCT ruling related to the application of past PUCT rulings addressing transition to competition in Texas.
The other variance is primarily caused by various operational effects of the jurisdictional separation on revenues and fuel andongoing purchased power expenses.
Entergy Texas, Inc.
Management's Financial Discussioncapacity and Analysis
Gross operating revenues, fuel and purchased power expenses, and other regulatory charges
Gross operating revenues increased $229.3 million primarily due to the following reasons:base rate increases and the volume/weather effect, as discussed above.
· | an increase of $157 million in fuel cost recovery revenues due to higher fuel rates and increased usage, partially offset by interim fuel refunds to customers for fuel cost recovery over-collections through November 2007. The refund was distributed over a two-month period beginning February 2008. The interim refund and the PUCT approval is discussed in Note 2 to the financial statements; |
· | an increase of $37.1 million in affiliated wholesale revenue primarily due to increases in the cost of energy; |
· | an increase in transition charge amounts collected from customers to service the securitization bonds as discussed above. See Note 5 to the financial statements for additional information regarding the securitization bonds; and |
· | implementation of an interim surcharge to collect $10.3 million in under-recovered incremental purchased capacity costs incurred through July 2007. The surcharge was collected over a two-month period beginning February 2008. The incremental capacity recovery rider and PUCT approval is discussed in Note 2 to the financial statements. |
Fuel and purchased power expenses increased primarily due to an increase in power purchases as a result of the purchased power agreements between Entergy Gulf States Louisiana and Entergy Texas anddemand coupled with an increase in the average market prices of purchased power and natural gas, substantially offset by a decrease in deferred fuel expense as a result of decreased recovery from customerslower fuel refunds in 2011 versus 2010, partially offset by a decrease in the average market price of fuel costs.natural gas.
Other regulatory charges increaseddecreased primarily due to an increase of $6.9 millionthe distribution in the recoveryfirst quarter 2011 of bond expenses related$17.4 million to customers of the securitization bonds. The recovery became effective July 2007.2007 rough production cost equalization remedy receipts. See Note 52 to the financial statements for additional information regardingfurther discussion of the securitization bonds.rough production cost equalization proceedings.
Other Income Statement Variances
20092012 Compared to 20082011
Other operation and maintenance expenses increased primarily due to:
| · | an increase of $11.4$7.2 million in fossilfossil-fueled generation expenses primarily due to higher plant maintenancea greater scope of work and an additional outage in 2012 compared to 2011; |
| · | $4.8 million of costs incurred in 2012 related to the planned spin-off and plant outages;merger of the Utility’s transmission business; |
| · | the amortization of $4.3 million of Hurricane Rita storm costs in accordance with a rate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the PUCT rate order; |
| · | an increase of $6.8$3.5 million in compensation and benefit costs primarily due to the Hurricane Ikedecreasing discount rates and Hurricane Gustav storm cost recovery settlement agreement, as discussedchanges in certain actuarial assumptions resulting from an experience study. See “Critical Accounting Estimates” below under "Hurricane Ike and Hurricane Gustav";for further discussion of benefits costs; |
| · | an increase of $1.8$2.7 million in transmission spending primarily for costs related to the Independent Coordinator of Transmission and substation maintenance; |
· | an increase of $1.8 millionloss reserves in local easement fees as the result of higher gross revenues in certain locations within the Texas jurisdiction;2012; and |
| · | an increase of $1.7$2.3 million in customer service costs primarily asstorm damage reserves in accordance with a resultrate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of write-offs of uncollectible customer accounts.the PUCT rate order. |
Other income increased primarily due to carrying charges on Hurricane Ike storm restoration costs as authorized by Texas legislation in the second quarter 2009,The increase was partially offset by a decrease of $1.8 million in energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income.
Taxes other than income taxes collected on advancesdecreased primarily due to a reduction in the provision recorded for transmission projectssales and use taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service and an increase in depreciation rates as a decreaseresult of the rate order approved by the PUCT in interest earned on money pool investments.September 2012. See Note 2 to the financial statements for further discussion of Hurricane Ike storm cost recovery filings.the rate order.
Interest expense increasedOther income decreased primarily due to an increasethe reversal of $6.7 million of disallowed carrying charges on Hurricane Rita storm restoration costs in long-term debt outstanding asaccordance with a resultrate order from the PUCT issued in September 2012. See Note 2 to the financial statements for further discussion of the issuance of $500 million of 7.125% Series mortgage bonds in January 2009 and the issuance of $150 million of 7.875% Series mortgage bonds in May 2009, partially offset by pay-down of debt assumption agreement liabilities.PUCT rate order.
Entergy Texas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
20082011 Compared to 20072010
Other operation and maintenance expenses decreasedincreased primarily due to:
| · | a decreasean increase of $4.7$8.5 million in transmission spending primarilyexpenses due to lowera billing adjustment recorded in the fourth quarter 2011 related to prior transmission investment equalization expenses;costs (for the approximate period of 1996 - 2011) allocable to Entergy Texas under the System Agreement; |
| · | a decreasean increase of $3.9$2.4 million in plant maintenance costs;energy efficiency costs. These costs are recovered through the energy efficiency rider and have no effect on net income; and |
| · | a decrease of $3.6 million in customer service support costs, including a decrease in customer account write-offs.several individually insignificant items. |
The decreaseincrease was partially offset by an increasethe amortization of $7.3$11 million of rate case expenses in 2010 and a decrease of $3.9 million in compensation and benefits costs primarily due to the write-off of certain disallowed costs resulting from the December 2008 rate case settlement agreement filed with the PUCT and an increase of $1.7a decrease in payroll and payroll-related costs. The rate case settlement agreement is discussed instock option expense. See Note 2 to the financial statements.statements for further discussion of the rate case settlement.
Taxes other than income taxes increased primarily due to an increase in local franchise taxes as a result of higher city franchise and gross receipts taxes and an increase in ad valorem taxes due to a higher 2011 assessment as compared to 2010, partially offset by lower street rentals.
Depreciation and amortization expenses increased primarily due to an increase in plant in service.
Other income decreased primarily due to the absence of carrying charges on storm restoration costs that were approved by the PUCT in the fourth quarter 2006 and a decrease in interest earned on money pool investments. In June 2007, Entergy Gulf States Reconstruction Funding I, LLC issued securitization bonds and the carrying charges ended. The PUCT approval of carrying charges, the securitization filing and the approval for the recovery of reconstruction costs are discussed in Note 2 to the financial statements. The decrease was partially offset by an increase in taxes collected on advances for transmission projects.
Interest and other charges decreased primarily due to the absence of interest recorded on advances from independent power producers per a FERC order during the first quarter 2007 and a decrease in debt outstanding under the debt assumption agreement. This decrease was partially offset by an increase in interest charges recorded on the securitization bonds which were issued during the second quarter 2007. See Note 5 to the financial statements for additional information regarding the securitization bonds.
Income Taxes
The effective income tax rates were 36.6%44.1%, 32.7%38.0%, and 38.1%39.0% for 2009, 2008,2012, 2011, and 2007,2010, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rate.rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2009 | | 2008 | | 2007 | | 2012 | | | 2011 | | | 2010 | |
| | | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | | $2,239 | | $297,082 | | $77,115 | | $ | 65,289 | | | $ | 35,342 | | | $ | 200,703 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | |
| | Operating activities | | 287,533 | | 1,444 | | 175,991 | |
| | Investing activities | | (216,649) | | (116,887) | | (234,716) | |
| | Financing activities | | 127,580 | | (179,400) | | 278,692 | |
| | Net increase (decrease) in cash and cash equivalents | | 198,464 | | (294,843) | | 219,967 | |
| Net cash provided by (used in): | | | | | | | | | | | | | |
| Operating activities | | | | 271,081 | | | | 238,837 | | | | 43,095 | |
| Investing activities | | | | (128,904 | ) | | | (219,783 | ) | | | (121,439 | ) |
| Financing activities | | | | (147,230 | ) | | | 10,893 | | | | (87,017 | ) |
| Net increase (decrease) in cash and cash equivalents | | | | (5,053 | ) | | | 29,947 | | | | (165,361 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | | $200,703 | | $2,239 | | $297,082 | | $ | 60,236 | | | $ | 65,289 | | | $ | 35,342 | |
Operating Activities
Net cash provided by operating activities increased $32.2 million in 2012 compared to 2011 primarily due to:
| · | an increase in the recovery of fuel costs due to System Agreement bandwidth remedy payments of $43 million received in January 2012 as a result of receipts required to implement the FERC’s remedy in an October 2011 order for the period June-December 2005. In the fourth quarter 2012, Entergy Texas customers were credited $28.4 million. See Note 2 to the financial statements for a discussion of the System Agreement proceedings; |
Entergy Texas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
Operating Activities
| · | a decrease of $9.1 million in pension contributions. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits; and |
| · | $67.2 million of fuel cost refunds in 2012 compared to $73.4 million of fuel cost refunds in 2011. See Note 2 to the financial statements for discussion of the fuel cost refunds. |
The increase was partially offset by a decrease of $11.3 million in income tax refunds.
Cash flowNet cash provided by operating activities increased $286.1$195.7 million in 20092011 compared to 20082010 primarily due to:
| · | the timing$73.4 million of collection of receivables from customers; |
· | increased recovery of deferred fuel costs. The increased fuel recovery was primarily caused by the $71 million fuel cost over-recovery refundrefunds in 2008 that is discussed2011 versus $179.5 million of fuel cost refunds in 2010. See Note 2 to the financial statements in addition tofor discussion of the over-recovery of fuel costs in 2009 compared to 2008;cost refunds; and |
| · | income tax refunds of $72.3$13.5 million in 20092011 compared to income tax payments of $762 thousand in 2008; and |
· | a decrease of $15.3$48.7 million in pension contributions.2010. |
The increase was partially offset by Hurricane Ike restoration spending in 2008.
Cash flow provided by operating activities decreased $174.5 million in 2008 compared to 2007 primarily due to Hurricane Ike restoration spending, decreased recovery of deferred fuel costs, and an increase of $9.9 million in pension contributions, partially offset by the timing of collections of receivables from customers and payments to vendors. The decreased fuel recovery was primarily caused by the $71 million fuel cost over-recovery refund that is discussed in Note 2 to the financial statements, in addition to the over-recovery of fuel costs for the year ended December 31, 2007 compared to under-recovering for the year ended December 31, 2008. Fuel prices increased and due to the time lag before the fuel recovery rate increases in response, Entergy Texas had under-recovered fuel costs in 2008.
Investing Activities
Cash flowNet cash used in investing activities increased $99.8decreased $90.9 million in 20092012 compared to 20082011 primarily due to money pool activity, partially offset by higher fossil-fueled generation construction expenditures in 2008 due to Hurricane Ikea greater scope of projects in 2012.
Decreases in Entergy Texas’s receivable from the money pool are a source of cash flow, and insurance proceeds receivedEntergy Texas’s receivable from the money pool decreased by $44 million in 2009 relating2012 compared to Hurricane Ike.increasing by $49.5 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce Entergy’s subsidiaries’ need for external short-term borrowings.
Net cash used in investing activities increased $98.3 million in 2011 compared to 2010 primarily due to money pool activity.
Increases in Entergy Texas'Texas’s receivable from the money pool are a use of cash flow, and Entergy Texas'Texas’s receivable from the money pool increased by $69.3$49.5 million in 20092011 compared to decreasing by $154.2$55.6 million in 2008. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries' need for external short-term borrowings.
Cash flow used in investing activities decreased $117.8 million in 2008 compared to 2007 primarily due to money pool activity, partially offset by an increase in distribution construction expenditures primarily due to Hurricane Ike.
Decreases in Entergy Texas' receivable from the money pool are a source of cash flow, and Entergy Texas' receivable from the money pool decreased by $154.2 million for 2008 compared to increasing by $56.9 million for 2007.2010.
Financing Activities
FinancingEntergy Texas’s financing activities used $147.2 million in 2012 compared to providing $10.9 million in 2011 primarily due to an increase of $81.4 million in common stock dividends paid and the issuance of $75 million of 4.10% Series first mortgage bonds in September 2011.
Entergy Texas’s financing activities provided $10.9 million of cash of $127.6 million for 2009in 2011 compared to using $87.0 million of cash of $179.4 million for 2008in 2010 primarily due to:
| · | the issuanceretirement of $545.9$199 million of debt assumption liabilities and securitization bonds in 2010 compared to the retirement of $57.4 million of securitization bonds in November 2009. See Note 5 to the financial statements for additional information regarding the securitization bonds; |
· | the issuance of $500 million of 7.125% Series Mortgage Bonds in January 2009; |
· | the issuance of $150 million of 7.875% Series Mortgage Bonds in May 2009;2011; and |
| · | $150a decrease of $80.6 million of capital returned to Entergy Corporation in February 2008. After the effects of Hurricane Katrina and Hurricane Rita, Entergy Corporation made a $300 million capital contribution to Entergy Gulf States, Inc. in 2005, which was part of Entergy's financing plan that provided liquidity and capital resources to Entergy and its subsidiaries while storm restoration cost recovery was pursued.common equity distributions. |
The cash provided was partially offset by the issuance of $200 million of 3.60% Series mortgage bonds in May 2010 compared to the issuance of $75 million of 4.10% Series first mortgage bonds in September 2011.
Entergy Texas, Inc. and Subsidiaries
Management'sManagement’s Financial Discussion and Analysis
The cash provided was partially offset by:
· | the retirement of $619.9 million of long term debt in 2009 compared to $327.5 million in 2008; |
· | the repayment of $100 million outstanding on Entergy Texas' credit facility in February 2009 as compared to borrowings of $100 million on Entergy Texas' credit facility in 2008; |
· | the repayment of Entergy Texas' $160 million note payable from Entergy Corporation in January 2009; |
· | an increase of $107.5 million in common stock dividends paid; and |
Decreases in Entergy Texas' payable to the money pool are a use of cash flow, and Entergy Texas' payable to the money pool decreased by $50.8 million in 2009 compared to increasing by $50.8 million in 2008. The money pool is an inter-company borrowing arrangement designed to reduce Entergy's subsidiaries need for external short-term borrowings.
Financing activities used cash of $179.4 million for 2008 compared to providing cash of $278.7 million for 2007 primarily due to:
· | the issuance of $329.5 million of securitization bonds in June 2007. See Note 5 to the financial statements for additional information regarding the securitization bonds; |
· | the retirement of $327.5 million of long-term debt in 2008; and |
· | $150 million of capital returned to Entergy Corporation in February 2008. After the effects of Hurricane Katrina and Hurricane Rita, Entergy Corporation made a $300 million capital contribution to Entergy Gulf States, Inc. in 2005, which was part of Entergy's financing plan that provided liquidity and capital resources to Entergy and its subsidiaries while storm restoration cost recovery was pursued. |
The use of cash was partially offset by:
· | borrowing $160 million from Entergy Corporation in December 2008; |
· | borrowings of $100 million on Entergy Texas' credit facility; and |
Increases in Entergy Texas' payable to the money pool are a source of cash flow, and Entergy Texas' payable to the money pool increased by $50.8 million for 2008.
Capital Structure
Entergy Texas'Texas’s capitalization is balanced between equity and debt, as shown in the following table. The increase in the debt to capital ratio for Entergy Texas as of December 31, 2009 is primarily due to the issuance of $500 million 7.125% Series mortgage bonds in January 2009, the issuance of $150 million 7.875% Series mortgage bonds in May 2009, and the issuance of $545.9 million senior secured transition bonds (securitization bonds) in November 2009 (which are non-recourse to Entergy Texas), partially offset by the repayment of Entergy Texas' $160 million note payable from Entergy Corporation in January 2009, the repayment of $100 million outstanding on Entergy Texas' credit facility in February 2009, and the retirement of $619.9 million of long-term debt prior to maturity.
| | | December 31, 2009 | | December 31, 2008 |
| | | | | |
| Net debt to net capital | | 63.3% | | 59.9% |
| Effect of subtracting cash from debt | | 3.0% | | 0.0% |
| Debt to capital | | 66.3% | | 59.9% |
Entergy Texas, Inc.
Management's Financial Discussion and Analysis| | | December 31, 2012 | | December 31, 2011 |
| | | | | |
| Debt to capital | | 65.4% | | 65.1% |
| Effect of excluding the securitization bonds | | (13.3%) | | (14.3%) |
| Debt to capital, excluding securitization bonds (1) | | 52.1% | | 50.8% |
| Effect of subtracting cash | | (1.7%) | | (1.9%) |
| Net debt to net capital, excluding securitization bonds (1) | | 50.4% | | 48.9% |
| (1) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Texas. |
Net debt consists of debt less cash and cash equivalents. Debt consists of notes payable and long-term debt, including the currently maturing portion and also including the debt assumption liability.portion. Capital consists of debt and shareholders'common equity. Net capital consists of capital less cash and cash equivalents. Entergy Texas uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas'Texas’s financial condition.
Uses of Capital
Entergy Texas requires capital resources for:
| · | construction and other capital investments; |
| · | debt maturities including payments under the debt assumption agreement with Entergy Gulf States Louisiana;or retirements; |
| · | working capital purposes, including the financing of fuel and purchased power costs; and |
| · | dividend and interest payments. |
Following are the amounts of Entergy Texas'Texas’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:obligations.
| | 2010 | | 2011-2012 | | 2013-2014 | | after 2014 | | Total | | 2013 | | 2014-2015 | | 2016-2017 | | After 2017 | | Total |
| | (In Millions) | (In Millions) |
| Planned construction and | | | | | | | | | | | |
| capital investment (1) | $180 | | $425 | | N/A | | N/A | | $605 | | |
| Planned construction and capital investment (1): | | Planned construction and capital investment (1): | | | | | | | |
| Generation | | $76 | | $94 | | N/A | | N/A | | $170 |
| Transmission | | 43 | | 177 | | N/A | | N/A | | 220 |
| Distribution | | 75 | | 146 | | N/A | | N/A | | 221 |
| Other | | 7 | | 17 | | N/A | | N/A | | 24 |
| Total | | $201 | | $434 | | N/A | | N/A | | $635 |
| Long-term debt (2) | $260 | | $166 | | $219 | | $2,054 | | $2,699 | | $88 | | $372 | | $253 | | $1,729 | | $2,442 |
| Operating leases | $4 | | $8 | | $6 | | $2 | | $20 | | $6 | | $9 | | $4 | | $2 | | $21 |
| Purchase obligations (3) | $52 | | $130 | | $117 | | $239 | | $538 | | $98 | | $126 | | $119 | | $247 | | $590 |
| (1) | Includes approximately $106$124 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment or systems and to support normal customer growth. The planned amounts do not reflect the expected reduction in capital expenditures that would occur if the planned spin-off and merger of the transmission business with ITC Holdings occurs. |
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For Entergy Texas, it primarily includes unconditional fuel and purchased power obligations. |
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to the contractual obligations given above, Entergy Texas expects to contribute approximately $9.7$6.7 million to its pension plans and approximately $7.7$5.2 million to other postretirement plans in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the2013. See "Critical Accounting Estimates – Qualified Pension Protection Actand Other Postretirement Benefits" below for a discussion of 2006 rules, effective for the 2008 plan yearqualified pension and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Texas’ pension contributions in the future.other postretirement benefits funding.
Entergy'sAlso in addition to the contractual obligations, Entergy Texas has $12.4 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
Entergy’s Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above. The estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints, environmental compliance, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt and preferred stock maturities in NotesNote 5 and 6 to the financial statements.
As a wholly-owned subsidiary, Entergy Texas pays dividends to Entergy Corporation from its earnings at a percentage determined monthly.
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
Sources of Capital
Entergy Texas'Texas’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | debt or preferred stock issuances; and |
| · | bank financing under new or existing facilities. |
Entergy Texas may refinance, redeem, or redeemotherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Preferred stock and debtDebt issuances are also subject to issuance tests set forth in its corporate charter, bond indentures and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Texas'Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years:years.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $69,317 | | ($50,794) | | $154,176 | | $97,277 |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $19,175 | | $63,191 | | $13,672 | | $69,317 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas has a credit facility in the amount of $100$150 million scheduled to expire in August 2012.March 2017. No borrowings were outstanding under the facility as of December 31, 2009.2012. See Note 4 to the financial statements for additional discussion of the credit facility.
Entergy Texas has obtained short-term borrowing authorization through October 2013 from the FERC under which it may borrow through October 2011, up to the aggregate amount, at any one time outstanding, of $200 million.million in the aggregate. See Note 4 to the financial statements for further discussion of Entergy Texas'Texas’s short-term borrowing limits. Entergy Texas has also obtained an order from the FERC authorizing long-term securities issuances through July 2011.
In December 2008, Entergy Texas borrowed $160 million from its parent company, Entergy Corporation, under a $300 million revolving credit facility pursuant to an Inter-Company Credit Agreement between Entergy Corporation and Entergy Texas. This borrowing would have matured on December 3, 2013. Entergy Texas used these borrowings, together with other available corporate funds, to pay at maturity the portion of the $350 million Floating Rate series of First Mortgage Bonds due December 2008 that had been assumed by Entergy Texas, and that bond series is no longer outstanding. In January 2009, Entergy Texas repaid its $160 million note payable to Entergy Corporation with the proceeds from the $500 million bond issuance discussed above.
Hurricane Ike and Hurricane Gustav
In September 2008, Hurricane Ike caused catastrophic damage to Entergy Texas' service territory. The storm resulted in widespread power outages, significant damage to distribution, transmission, and generation infrastructure, and the loss of sales during the power outages. Entergy Texas filed an application in April 2009 seeking a determination that $577.5 million of Hurricane Ike and Hurricane Gustav restoration costs are recoverable, including estimated costs for work to be completed. On August 5, 2009, Entergy Texas submitted to the ALJ an unopposed settlement agreement intended to resolve all issues in the storm cost recovery case. Under the terms of the agreement $566.4 million, plus carrying costs, are eligible for recovery. Insurance proceeds will be credited as an offset to the securitized amount. Of the $11.1 million difference between Entergy Texas' request and the amount agreed to, which is part of the black box agreement and not directly attributable to any specific individual issues raised, $6.8 million is operation and maintenance expense for which Entergy Texas recorded a charge in the second quarter 2009. The remaining $4.3 million was recorded as utility plant. The PUCT approved the settlement in August 2009, and in September 2009 the PUCT approved recovery of the costs, plus carrying costs, by securitization. See Note 5 to the financial statements for a discussion of the November 2009 issuance of the securitization bonds.
Entergy Texas, Inc. and Subsidiaries
Management's Financial Discussion and Analysis
In the third quarter 2009, Entergy settled with its insurer on its Hurricane Ike claim and Entergy Texas received $75.5 million in proceeds (Entergy received a total of $76.5 million).
Hurricane Rita
In September 2005, Hurricane Rita hit Entergy Texas' service territory. The storm resulted in power outages; significant damage to electric distribution, transmission, and generation infrastructure; and the temporary loss of sales and customers due to mandatory evacuations. In July 2006, Entergy Texas filed an application with the PUCT with respect to its Hurricane Rita reconstruction costs incurred through March 2006. The filing asked the PUCT to determine the amount of reasonable and necessary hurricane reconstruction costs eligible for securitization and recovery, approve the recovery of carrying costs, and approve the manner in which Entergy Texas allocates those costs among its retail customer classes. In December 2006, the PUCT approved $381 million of reasonable and necessary hurricane reconstruction costs incurred through March 31, 2006, plus carrying costs, as eligible for recovery. After netting expected insurance proceeds, the amount is $353 million. In April 2007, the PUCT issued its financing order authorizing the issuance of securitization bonds to recover the $353 million of hurricane reconstruction costs and up to $6 million of transaction costs, offset by $32 million of related deferred income tax benefits. See Note 5 to the financial statements for a discussion of the June 2007 issuance of the securitization bonds.
Entergy received a total of $317 million as of December 31, 2009 on its Hurricane Katrina and Hurricane Rita insurance claims, including the settlements of its Hurricane Katrina claims with each of its two excess insurers. Of the $317 million received, $34 million has been allocated to Entergy Texas. Entergy has substantially completed its insurance recoveries related to Hurricane Rita.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that requires Entergy Texas to cease all activities relating to Entergy Texas' transition to competition. The law allows Entergy Texas to remain a part of the SERC Region, although it does not prevent Entergy Texas from joining the Southwest Power Pool. The law provides that proceedings to certify a power region that Entergy Texas belongs to as a qualified power region can be initiated by the PUCT, or on motion by another party, when the conditions supporting such a proceeding exist. Under the new law, the PUCT may not approve a transition to competition plan for Entergy Texas until the expiration of four years from the PUCT's certification of Entergy Texas' power region. In response to the new law, Entergy Texas in June 2009 gave notice to the PUCT of the withdrawal of its previously filed transition to competition plan, and requested that its transition to competition proceeding be dismissed. In July 2009 the ALJ dismissed the proceeding.
The new law also contains provisions that allow Entergy Texas to be included in a cost recovery mechanism that permits annual filings for the recovery of reasonable and necessary expenditures for transmission infrastructure improvement and changes in wholesale transmission charges. This mechanism was previously available to other non-ERCOT Texas utility companies, but not to Entergy Texas.
The new law further amends already existing law that had required Entergy Texas to propose for PUCT approval a tariff to allow eligible customers the ability to contract for competitive generation. The amending language in the new law provides, among other things, that: 1) the tariff shall not be implemented in a manner that harms the sustainability or competitiveness of manufacturers who choose not to participate in the tariff; 2) Entergy Texas shall "purchase competitive generation service, selected by the customer, and provide the generation at retail to the customer"; and 3) Entergy Texas shall provide and price transmission service and ancillary services under that tariff at a rate that is unbundled from its cost of service. The new law directs that the PUCT may not issue an order on the tariff that is contrary to an applicable decision, rule, or policy statement of a federal regulatory agency having jurisdiction. The new law provides that the PUCT shall approve, reject, or modify the proposed tariff not later than September 1, 2010.
Entergy Texas, Inc.
Management'sManagement’s Financial Discussion and Analysis
State and Local Rate Regulation and Fuel-Cost Recovery
The rates that Entergy Texas charges for its services significantly influence its financial position, results of operations, and liquidity. Entergy Texas is regulated and the rates charged to its customers are determined in regulatory proceedings. The PUCT, a governmental agency, is primarily responsible for approval of the rates charged to customers.
Filings with the PUCT
2009 Rate Case
In December 2009, Entergy Texas filed a rate case requesting a $198.7 million increase reflecting an 11.5% return on common equity based on an adjusted June 2009 test year. The filing includes a proposed cost of service adjustment rider with a three-year term beginning with the 2010 calendar year as the initial evaluation period. Key provisions include a plus or minus 15 basis point bandwidth, with earnings outside the bandwidth reset to the bottom or top of the band and rates changing prospectively depending upon whether Entergy Texas is under or over-earning. The annual change in revenue requirement is limited to a percentage change in the Consumer Price Index for urban areas, and the filing includes a provision for extraordinary events greater than $10 million per year that would be considered separately. The filing also proposes a purchased power recovery rider and a competitive generation service tariff, and will establish test year baseline values to be used in the transmission cost recovery factor rider authorized for use by Entergy Texas in the 2009 legislative session. The rate case also includesincluded a $2.8 million revenue requirement to provide supplemental funding for the decommissioning trust maintained for the 70% share of River Bend for which Entergy Texas retail customers are partially responsible, in response to an NRC notification of a projected shortfall of decommissioning funding assurance. The filing also includes a request to reconcile $1.8 billion of fuel and purchased power costs covering the period April 2007 through June 2009. Hearings in the proceeding are scheduled for July 2010, and the PUCT is required to issue a final order by November 1, 2010. Beginning in May 2010, Entergy Texas will be allowed to implementimplemented a $17.5 million interim rate increase, subject to refund. Intervenors and PUCT Staff filed testimony recommending adjustments that would result in a maximum rate increase, based on the PUCT Staff’s testimony, of $58 million.
The ratesparties filed a settlement in August 2010 intended to resolve the rate case proceeding. The settlement provided for a $59 million base rate increase for electricity usage beginning August 15, 2010, with an additional increase of $9 million for bills rendered beginning May 2, 2011. The settlement stipulated an authorized return on equity of 10.125%. The settlement stated that Entergy Texas's fuel costs for the period April 2007 through June 2009 are reconciled, with $3.25 million of disallowed costs, which were included in an interim fuel refund. The settlement also set by a final order will be effective back to September 13,River Bend decommissioning costs at $2.0 million annually. Consistent with the settlement, in the third quarter 2010, Entergy Texas amortized $11 million of rate case costs. The PUCT approved the settlement in December 2010.
20072011 Rate Case
In November 2011, Entergy Texas madefiled a rate filing in September 2007 withrequesting a $112 million base rate increase reflecting a 10.6% return on common equity based on an adjusted June 2011 test year. The rate case also proposed a purchased power recovery rider. On January 12, 2012, the PUCT requesting an annualvoted not to address the purchased power recovery rider in the current rate increase totaling $107.5 million, includingcase, but the PUCT voted to set a baseline in the rate case proceeding that would be applicable if a purchased power capacity rider is approved in a separate proceeding. In April 2012 the PUCT Staff filed direct testimony recommending a base rate increase of $64.3$66 million and riders totaling $43.2 million. On December 16, 2008, Entergy Texasa 9.6% return on common equity. The PUCT Staff, however, subsequently filed a term sheet that reflected a settlement agreement that included the PUCT Staff and the other active participantsstatement of position in the rate case. On December 19, 2008,proceeding indicating that it was still evaluating the ALJs approvedposition it would ultimately take in the case regarding Entergy Texas' request to implement interim rates reflecting the agreement. The agreement includes a $46.7 million base rate increase, among other provisions. Under the ALJs' interim order, Entergy Texas implemented interim rates, subject to refund and surcharge, reflecting the rates established through the settlement. These rates became effective with bills rendered on and after January 28, 2009, for usage on and after December 19, 2008. In addition, the existingTexas’s recovery mechanism for incrementalof purchased power capacity costs ceased asand Entergy Texas’s proposal to defer its MISO transition expenses. In April 2012, Entergy Texas filed rebuttal testimony indicating a revised request for a $105 million base rate increase. A hearing was held in late-April through early-May 2012.
In September 2012, the PUCT issued an order approving a $28 million rate increase, effective July 2012. The order includes a finding that “a return on common equity (ROE) of January 28, 2009, with9.80 percent will allow [Entergy Texas] a reasonable opportunity to earn a reasonable return on invested capital.” The order also provides for increases in depreciation rates and the annual storm reserve accrual. The order also reduced Entergy Texas’s proposed purchased power capacity costs, then subsumed within thestating that they are not known and measureable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6 million of MISO transition expense in base rates, setand reduced Entergy’s
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Texas’s fuel reconciliation recovery by $4.0 million because it disagreed with the line-loss factor used in this proceeding. The agreement adopted bythe calculation. After considering the progress of the proceeding in light of the PUCT order, Entergy Texas recorded in the third quarter 2012 an approximate $24 million charge to recognize that assets associated with Hurricane Rita, financially-based incentive compensation, and fuel recovery are no longer probable of recovery. Entergy Texas continues to believe that it is entitled to recover these prudently incurred costs, however, and it filed a motion for rehearing regarding these and several other issues in the PUCT’s order on October 4, 2012. Several other parties have also reconciles fuel and purchased power costsfiled motions for rehearing of the period January 1, 2006 through March 31, 2007. CertainPUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, municipalities exercised their original jurisdiction and took final actionhave appealed the PUCT’s order to approve rates consistent with the interim rates approved by the ALJs. In March 2009, the PUCT approved the settlement, which made the interim rates final.Travis County District Court.
Fuel and Purchased Power Cost Recovery
Entergy Texas'Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including carrying charges, not recovered in base rates. The fixed fuel factor formula was revised and approved by a PUCT order in August 2006. The new formula was implemented in September 2006. Under the new methodology, semi-annualSemi-annual revisions of the fixed fuel factor will continue to beare made in March and September based on the market price of natural gas and changes in fuel mix. The amounts collected under Entergy Texas'Texas’s fixed fuel factor and any interim surcharge or refund are subject to fuel reconciliation proceedings before the PUCT.
In July 2005, Entergy Texas filed with the PUCT a request for implementation of an incremental purchased capacity recovery rider. Through this rider Entergy Texas sought to recover incremental revenues that represent the incremental purchased capacity costs, including Entergy Texas' obligation to purchase power from Entergy Louisiana's Perryville plant, over what is already in Entergy Texas' base rates. The PUCT approved an initial rider to collect $18 million annually, which was increased to $21 million in subsequent years. Under the
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
settlement of the 2007 rate case discussed above, this rider ceased on January 28, 2009, with the implementation of stipulated base rates. The amounts collected through the rider are subject to reconciliation.
In May 2006, Entergy Texas filed with the PUCT a fuel and purchased power reconciliation case covering the period September 2003 through December 2005 for costs recoverable through the fixed fuel factor rate and the incremental purchased capacity recovery rider. Entergy Texas sought reconciliation of $1.6 billion of fuel and purchased power costs on a Texas retail basis. A hearing was conducted before the ALJs in April 2007. In July 2007, the ALJs issued a proposal for decision recommending that Entergy Texas be authorized to reconcile all of its requested fixed fuel factor expenses and recommending a minor exception to the incremental purchased capacity recovery calculation. The ALJs also recommended granting an exception to the PUCT rules to allow for recovery of an additional $11.4 million in purchased power capacity costs. In September 2007, the PUCT issued an order, which affirmed the ultimate result of the ALJs' proposal for decision. Upon motions for rehearing, the PUCT added additional language in its order on rehearing to further clarify its position that 30% of River Bend should not be regulated by the PUCT. Two parties filed a second motion for rehearing, but the PUCT declined to address them. The PUCT's decision has been appealed to the Travis County District Court.
In March 2007, Entergy Texas filed a request with the PUCT to refund $78.5 million, including interest, of fuel cost recovery over-collections through January 2007. In June 2007 the PUCT approved a unanimous stipulation and settlement agreement that updated the over-collection balance through April 2007 and established a refund amount, including interest, of $109.4 million. The refund was made over a two-month period beginning with the first billing cycle in July 2007.
In October 2007, Entergy Texas filed a request with the PUCT to refund $45.6 million, including interest, of fuel cost recovery over-collections through September 2007. In January 2008, Entergy Texas filed with the PUCT a stipulation and settlement agreement among the parties that updated the over-collection balance through November 2007 and established a refund amount, including interest, of $71 million. The PUCT approved the agreement in February 2008. The refund was made over a two-month period beginning February 2008, but was reduced by $10.3 million of under-recovered incremental purchased capacity costs.
In January 2008, Entergy Texas made a compliance filing with the PUCT describing how its 2007 Rough Production Cost Equalization receipts under the System Agreement were allocated between Entergy Gulf States, Inc.'s Texas and Louisiana jurisdictions. A hearing was held at the end of July 2008, and in October 2008 the ALJ issued a proposal for decision recommending an additional $18.6 million allocation to Texas retail customers. The PUCT adopted the ALJ's proposal for decision in December 2008. Because the PUCT allocation to Texas retail customers is inconsistent with the LPSC allocation to Louisiana retail customers, the PUCT's decision would result in trapped costs between the Texas and Louisiana jurisdictions with no mechanism for recovery. The PUCT denied Entergy Texas' motion for rehearing and Entergy Texas commenced proceedings in both state and federal district courts seeking to reverse the PUCT's decision. The federal proceeding has been abated pending further action by the FERC in the proceeding discussed below. No procedural schedule has been set for the state proceeding.
Entergy Texas also filed with the FERC a proposed amendment to the System Agreement bandwidth formula to specifically calculate the payments to Entergy Gulf States Louisiana and Entergy Texas of Entergy Gulf States, Inc.'s rough production cost equalization receipts for 2007. On May 8, 2009, the FERC issued an order rejecting the proposed amendment, stating, among other things, that the FERC does not have jurisdiction over the allocation of an individual utility's receipts/payments among or between its retail jurisdictions and that this was a matter for the courts to review in the pending proceedings noted above. Because of the FERC's order, Entergy Texas recorded the effects of the PUCT's allocation of the additional $18.6 million to retail customers in the second quarter 2009. On an after-tax basis, the charge to earnings was approximately $13.0 million (including interest). Entergy requested rehearing of the FERC's order, and on July 8, 2009, the FERC granted the request for rehearing for the limited purpose of affording more time for consideration of Entergy's request.
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
In May 2009, Entergy Texas filed with the PUCT a request to refund $46.1 million, including interest, of fuel cost recovery over-collections through February 2009. Entergy Texas requested that the proposed refund be made over a four-month period beginning June 2009. Pursuant to a stipulation among the various parties, in June 2009 the PUCT issued an order approving a refund of $59.2 million, including interest, of fuel cost recovery overcollections through March 2009. The refund was made over a three-month period beginning July 2009, with the exception of certain industrial and seasonal/agricultural customers who received a one-month refund.
In October 2009, Entergy Texas filed with the PUCT a request to refund approximately $71 million, including interest, of fuel cost recovery over-collections through September 2009. Entergy Texas requested that the proposed refund be made over a six-month period beginning January 2010. Pursuant to a stipulation among the various parties, the PUCT issued an order approving a refund of $87.8 million, including interest, of fuel cost recovery overcollections through October 2009. The refund will bewas made for most customers over a three-month period beginning January 2010.
In June 2010, Entergy Texas filed with the exceptionPUCT a request to refund approximately $66 million, including interest, of certain industrialfuel cost recovery over-collections through May 2010. In September 2010 the PUCT issued an order providing for a $77 million refund, including interest, for fuel cost recovery over-collections through June 2010. The refund was made for most customers over a three-month period beginning with the September 2010 billing cycle.
In December 2010, Entergy Texas filed with the PUCT a request to refund fuel cost recovery over-collections through October 2010. Pursuant to a stipulation among the parties that was approved by the PUCT in March 2011, Entergy Texas refunded over-collections through November 2010 of approximately $73 million, including interest through the refund period. The refund was made for most customers over a three-month period that began with the February 2011 billing cycle.
In December 2011, Entergy Texas filed with the PUCT a request to refund approximately $43 million, including interest, of fuel cost recovery over-collections through October 2011. Entergy Texas and seasonal/agriculturalthe parties to the proceeding reached an agreement that Entergy Texas would refund $67 million, including interest and additional over-recoveries through December 2011, over a three-month period. Entergy Texas and the parties requested that interim rates consistent with the settlement be approved effective with the March 2012 billing month, and the PUCT approved the application in March 2012. Entergy Texas completed this refund to customers who receivedin May 2012.
In October 2012, Entergy Texas filed with the PUCT a one-month refund.request to refund approximately $78 million, including interest, of fuel cost recovery over-collections through September 2012. Entergy Texas requested that the refund be implemented over a six-month period effective with the January 2013 billing month. Entergy Texas and the parties to the proceeding reached an agreement that Entergy Texas would refund $84 million, including interest and additional over-recoveries through October 2012, over a three-month period to most customers beginning January 2013. The PUCT approved the stipulation in January 2013.
In July 2012, Entergy Texas filed with the PUCT an application to credit its customers approximately $37.5 million, including interest, resulting from the FERC’s October 2011 order in the System Agreement rough production cost equalization proceeding. See Note 2 to the financial statements for a discussion of the FERC’s October 2011 order. In September 2012 the parties submitted a stipulation resolving the proceeding. The stipulation provides that most Entergy Texas customers will be credited over a four-month period beginning October 2012. The credits were initiated with the October 2012 billing month on an interim basis, and the PUCT subsequently approved the stipulation, also in October 2012.
In November 2012, Entergy Texas filed a pleading seeking a PUCT finding that special circumstances exist for limited cost recovery of capacity costs associated with two power purchase agreements until such time that these costs are included in base rates or a purchased capacity recovery rider or other recovery mechanism.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Federal Regulation
System Agreement Proceedings
See "“Independent Coordinator of Transmission”, “System Agreement Proceedings"”, “Entergy’s Proposal to Join MISO”, “Notice to SERC Reliability Corporation Regarding Reliability Standards and FERC Investigation”, and “U.S. Department of Justice Investigation” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries Management’s Financial Discussion and Analysis for a discussion of the proceeding at the FERC involving the System Agreement and of other related proceedings.
Transmission
See "Independent Coordinator of Transmission" in Entergy Corporation and Subsidiaries' Management's Discussion and Analysis for further discussion.these topics.
Industrial and Commercial Customers
Entergy Texas'Texas’s large industrial and commercial customers continually explore ways to reduce their energy costs. In particular, cogeneration is an option available to a portion of Entergy Texas'Texas’s industrial customer base. Entergy Texas responds by working with industrial and commercial customers and negotiating electric service contracts to provide, under existing rate schedules, competitive rates that match specific customer needs and load profiles. Entergy Texas actively participates in economic development, customer retention, and reclamation activities to increase industrial and commercial demand, from both new and existing customers. Entergy Texas does not currently expect additional significant losses to cogeneration because of the current economics of the electricity markets and Entergy Texas'Texas’s marketing efforts in retaining industrial customers.
Environmental Risks
Entergy Texas'Texas’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that Entergy Texas is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy Texas'Texas’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and the potential for future changes in the assumptions and measurements that could produce estimates that would have a material effect on the presentation of Entergy Texas'Texas’s financial position or results of operations.
Unbilled Revenue
As discussed in Note 1 to the financial statements, Entergy Texas records an estimate of the revenues earned for energy delivered since the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenue and a receivable, and the prior month'smonth’s estimate is reversed. The difference between the estimate of the unbilled receivable at the beginning of the period and the end of the period is the amount of unbilled revenue recognized during the period. The estimate recorded is primarily based upon an estimate of customer usage during the unbilled period and the billed price to customers in that month. Therefore, revenue recognized may be affected by the estimated price and usage at the beginning and end of each period and fuel price fluctuations, in addition to changes in certain components of the calculation.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries’ Management’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension and qualified projected benefit obligation cost to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $608 | | $6,517 | | (0.25%) | | $940 | | $12,621 |
| Rate of return on plan assets | | (0.25%) | | $610 | | - | | (0.25%) | | $657 | | $- |
| Rate of increase in compensation | | 0.25% | | $296 | | $1,312 | | 0.25% | | $372 | | $2,083 |
Entergy Texas, Inc.
Management's Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost toand accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $452 | | $5,005 |
| Health care cost trend | | 0.25% | | $432 | | $2,583 | | 0.25% | | $775 | | $4,676 |
| Discount rate | | (0.25%) | | $258 | | $3,017 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension incomecost for Entergy Texas in 20092012 was $0.8$10.4 million. Entergy Texas anticipates 20102013 qualified pension expensecost to be $3$14 million. Entergy Texas contributed $3.6$9.1 million to its qualified pension plans in 2009.2012. Entergy Texas'Texas’s contributions to the pension trust are currently estimated to be approximately $9.7$6.7 million in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of Entergy Texas’ pension contributions in the future.2013.
Total postretirement health care and life insurance benefit costs for Entergy Texas in 20092012 were $5.7$6 million, including $1$1.3 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Texas expects 20102013 postretirement health care and life insurance benefit costs to approximate $5.6$4.1 million, including $1.1$1.4 million in savings due to the estimated effect of future Medicare Part D subsidies. Entergy Texas expects to contribute approximately $7.7contributed $4.9 million to its other postretirement plans in 2010.2012 and expects to contribute approximately $5.2 million in 2013.
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries' Management'sSubsidiaries Management’s Financial Discussion and Analysis for a discussion of new accounting pronouncements.Analysis.
To the Board of Directors and Shareholder of
Entergy Texas, Inc. and Subsidiaries
Beaumont, Texas
We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 20092012 and 2008,2011, and the related consolidated income statements, consolidated statements of income, retained earnings and paid-in capital, and cash flows, and consolidated statements of changes in common equity (pages 376390 through 380394 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such consolidated financial statements present fairly, in all material respects, the financial position of Entergy Texas, Inc. and Subsidiaries as of December 31, 20092012 and 2008,2011, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the financial statements, effective December 31, 2007, Entergy Gulf States, Inc. completed a jurisdictional separation and contributed certain assets and liabilities to the Company.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
| |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,581,496 | | | $ | 1,757,199 | | | $ | 1,690,431 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 243,877 | | | | 352,022 | | | | 343,083 | |
| Purchased power | | | 717,876 | | | | 775,067 | | | | 743,438 | |
| Other operation and maintenance | | | 233,503 | | | | 214,191 | | | | 209,699 | |
| Taxes other than income taxes | | | 59,348 | | | | 69,329 | | | | 63,897 | |
| Depreciation and amortization | | | 88,307 | | | | 79,263 | | | | 76,057 | |
| Other regulatory charges - net | | | 68,772 | | | | 52,307 | | | | 63,683 | |
| TOTAL | | | 1,411,683 | | | | 1,542,179 | | | | 1,499,857 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 169,813 | | | | 215,020 | | | | 190,574 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 4,537 | | | | 3,781 | | | | 5,661 | |
| Interest and investment income | | | (2,220 | ) | | | 5,528 | | | | 7,222 | |
| Miscellaneous - net | | | (4,264 | ) | | | (3,047 | ) | | | (3,220 | ) |
| TOTAL | | | (1,947 | ) | | | 6,262 | | | | 9,663 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 96,035 | | | | 93,554 | | | | 95,272 | |
| Allowance for borrowed funds used during construction | | | (3,258 | ) | | | (2,609 | ) | | | (3,618 | ) |
| TOTAL | | | 92,777 | | | | 90,945 | | | | 91,654 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 75,089 | | | | 130,337 | | | | 108,583 | |
| | | | | | | | | | | | | |
| Income taxes | | | 33,118 | | | | 49,492 | | | | 42,383 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 41,971 | | | $ | 80,845 | | | $ | 66,200 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 41,971 | | | $ | 80,845 | | | $ | 66,200 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Depreciation and amortization | | | 88,307 | | | | 79,263 | | | | 76,057 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 123,167 | | | | 56,219 | | | | 63,418 | |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | 32,912 | | | | (39,640 | ) | | | (41,820 | ) |
| Fuel inventory | | | (1,504 | ) | | | (12 | ) | | | 1,085 | |
| Accounts payable | | | 19,980 | | | | (11,442 | ) | | | 23,415 | |
| Prepaid taxes and taxes accrued | | | (93,979 | ) | | | 11,760 | | | | (49,030 | ) |
| Interest accrued | | | (929 | ) | | | (582 | ) | | | 3,102 | |
| Deferred fuel costs | | | 28,670 | | | | (12,766 | ) | | | (25,318 | ) |
| Other working capital accounts | | | (58,691 | ) | | | 42,518 | | | | (115,753 | ) |
| Provisions for estimated losses | | | 1,585 | | | | (296 | ) | | | (3,390 | ) |
| Other regulatory assets | | | 62,166 | | | | (15,611 | ) | | | 51,637 | |
| Pension and other postretirement liabilities | | | 17,330 | | | | 64,686 | | | | (5,998 | ) |
| Other assets and liabilities | | | 10,096 | | | | (16,105 | ) | | | (510 | ) |
| Net cash flow provided by operating activities | | | 271,081 | | | | 238,837 | | | | 43,095 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (181,404 | ) | | | (173,462 | ) | | | (162,822 | ) |
| Allowance for equity funds used during construction | | | 4,537 | | | | 3,781 | | | | 5,661 | |
| Insurance proceeds | | | - | | | | - | | | | 5,293 | |
| Change in money pool receivable - net | | | 44,016 | | | | (49,519 | ) | | | 55,645 | |
| Increase in other investments | | | - | | | | - | | | | 2,318 | |
| Remittances to transition charge account | | | (88,367 | ) | | | (92,786 | ) | | | (89,939 | ) |
| Payments from transition charge account | | | 92,327 | | | | 92,203 | | | | 62,405 | |
| Other | | | (13 | ) | | | - | | | | - | |
| Net cash flow used in investing activities | | | (128,904 | ) | | | (219,783 | ) | | | (121,439 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | - | | | | 74,092 | | | | 198,435 | |
| Retirement of long-term debt | | | (59,322 | ) | | | (57,419 | ) | | | (199,052 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (87,180 | ) | | | (5,780 | ) | | | (86,400 | ) |
| Other | | | (728 | ) | | | - | | | | - | |
| Net cash flow provided by (used in) financing activities | | | (147,230 | ) | | | 10,893 | | | | (87,017 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | (5,053 | ) | | | 29,947 | | | | (165,361 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 65,289 | | | | 35,342 | | | | 200,703 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 60,236 | | | $ | 65,289 | | | $ | 35,342 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 92,632 | | | $ | 89,792 | | | $ | 87,147 | |
| Income taxes | | $ | (2,207 | ) | | $ | (13,538 | ) | | $ | 48,713 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 528 | | | $ | 150 | |
| Temporary cash investments | | | 59,708 | | | | 65,139 | |
| Total cash and cash equivalents | | | 60,236 | | | | 65,289 | |
| Securitization recovery trust account | | | 37,255 | | | | 41,215 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 53,836 | | | | 68,290 | |
| Allowance for doubtful accounts | | | (680 | ) | | | (1,461 | ) |
| Associated companies | | | 68,750 | | | | 129,561 | |
| Other | | | 10,450 | | | | 9,573 | |
| Accrued unbilled revenues | | | 38,252 | | | | 41,573 | |
| Total accounts receivable | | | 170,608 | | | | 247,536 | |
| Accumulated deferred income taxes | | | 34,988 | | | | 88,436 | |
| Fuel inventory - at average cost | | | 55,388 | | | | 53,884 | |
| Materials and supplies - at average cost | | | 32,853 | | | | 29,810 | |
| System agreement cost equalization | | | 16,880 | | | | - | |
| Prepaid taxes | | | 53,668 | | | | - | |
| Prepayments and other | | | 18,206 | | | | 15,203 | |
| TOTAL | | | 480,082 | | | | 541,373 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investments in affiliates - at equity | | | 678 | | | | 783 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 638 | | | | 930 | |
| Other | | | 17,263 | | | | 17,969 | |
| TOTAL | | | 18,579 | | | | 19,682 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,475,776 | | | | 3,338,608 | |
| Construction work in progress | | | 90,469 | | | | 90,856 | |
| TOTAL UTILITY PLANT | | | 3,566,245 | | | | 3,429,464 | |
| Less - accumulated depreciation and amortization | | | 1,332,349 | | | | 1,289,166 | |
| UTILITY PLANT - NET | | | 2,233,896 | | | | 2,140,298 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 131,287 | | | | 129,924 | |
Other regulatory assets (includes securitization property of $648,863 as of December 31, 2012 and $704,896 as of December 31, 2011) | | | 1,114,536 | | | | 1,178,067 | |
| Long-term receivables - associated companies | | | 29,510 | | | | 31,254 | |
| Other | | | 17,891 | | | | 18,408 | |
| TOTAL | | | 1,293,224 | | | | 1,357,653 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 4,025,781 | | | $ | 4,059,006 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Accounts payable: | | | | | | |
| Associated companies | | $ | 88,743 | | | $ | 60,583 | |
| Other | | | 65,261 | | | | 69,160 | |
| Customer deposits | | | 38,859 | | | | 38,294 | |
| Taxes accrued | | | - | | | | 40,311 | |
| Interest accrued | | | 32,166 | | | | 33,095 | |
| Deferred fuel costs | | | 93,334 | | | | 64,664 | |
| Pension and other postretirement liabilities | | | 853 | | | | 1,029 | |
| System agreement cost equalization | | | 8,968 | | | | 43,290 | |
| Other | | | 2,839 | | | | 4,847 | |
| TOTAL | | | 331,023 | | | | 355,273 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 1,009,081 | | | | 934,990 | |
| Accumulated deferred investment tax credits | | | 17,743 | | | | 19,339 | |
| Other regulatory liabilities | | | 6,150 | | | | 11,710 | |
| Asset retirement cost liabilities | | | 4,103 | | | | 3,870 | |
| Accumulated provisions | | | 6,609 | | | | 5,024 | |
| Pension and other postretirement liabilities | | | 155,241 | | | | 137,735 | |
Long-term debt (includes securitization bonds of $690,380 as of December 31, 2012 and $749,673 as of December 31, 2011) | | | 1,617,813 | | | | 1,677,127 | |
| Other | | | 23,872 | | | | 14,583 | |
| TOTAL | | | 2,840,612 | | | | 2,804,378 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| COMMON EQUITY | | | | | | | | |
| Common stock, no par value, authorized 200,000,000 shares; | | | | | | | | |
| issued and outstanding 46,525,000 shares in 2012 and 2011 | | | 49,452 | | | | 49,452 | |
| Paid-in capital | | | 481,994 | | | | 481,994 | |
| Retained earnings | | | 322,700 | | | | 367,909 | |
| TOTAL | | | 854,146 | | | | 899,355 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 4,025,781 | | | $ | 4,059,006 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | | | | |
| | | Common Equity | | | | |
| | | Common Stock | | | Paid-in Capital | | | Retained Earnings | | | Total | |
| | | (In Thousands) | | | | | | | |
| | | | | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 49,452 | | | $ | 481,994 | | | $ | 313,044 | | | $ | 844,490 | |
| Net income | | | - | | | | - | | | | 66,200 | | | | 66,200 | |
| Common stock dividends | | | - | | | | - | | | | (86,400 | ) | | | (86,400 | ) |
| Balance at December 31, 2010 | | $ | 49,452 | | | $ | 481,994 | | | $ | 292,844 | | | $ | 824,290 | |
| Net income | | | - | | | | - | | | | 80,845 | | | | 80,845 | |
| Common stock dividends | | | - | | | | - | | | | (5,780 | ) | | | (5,780 | ) |
| Balance at December 31, 2011 | | $ | 49,452 | | | $ | 481,994 | | | $ | 367,909 | | | $ | 899,355 | |
| Net income | | | - | | | | - | | | | 41,971 | | | | 41,971 | |
| Common stock dividends | | | - | | | | - | | | | (87,180 | ) | | | (87,180 | ) |
| Balance at December 31, 2012 | | $ | 49,452 | | | $ | 481,994 | | | $ | 322,700 | | | $ | 854,146 | |
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 1,563,823 | | | $ | 2,012,258 | | | $ | 1,782,923 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 449,335 | | | | 581,696 | | | | 546,413 | |
| Purchased power | | | 584,550 | | | | 965,426 | | | | 777,419 | |
| Other operation and maintenance | | | 204,524 | | | | 176,096 | | | | 179,119 | |
| Decommissioning | | | 195 | | | | 184 | | | | 173 | |
| Taxes other than income taxes | | | 55,480 | | | | 53,615 | | | | 50,617 | |
| Depreciation and amortization | | | 73,840 | | | | 75,125 | | | | 68,172 | |
| Other regulatory charges - net | | | 44,807 | | | | 24,197 | | | | 16,808 | |
| TOTAL | | | 1,412,731 | | | | 1,876,339 | | | | 1,638,721 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 151,092 | | | | 135,919 | | | | 144,202 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 5,232 | | | | 3,928 | | | | 3,295 | |
| Interest and dividend income | | | 47,541 | | | | 11,736 | | | | 31,397 | |
| Miscellaneous - net | | | 544 | | | | 12,387 | | | | (600 | ) |
| TOTAL | | | 53,317 | | | | 28,051 | | | | 34,092 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 98,957 | | | | 72,441 | | | | 74,343 | |
| Other interest - net | | | 7,206 | | | | 7,756 | | | | 10,907 | |
| Allowance for borrowed funds used during construction | | | (2,510 | ) | | | (2,240 | ) | | | (2,126 | ) |
| TOTAL | | | 103,653 | | | | 77,957 | | | | 83,124 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 100,756 | | | | 86,013 | | | | 95,170 | |
| | | | | | | | | | | | | |
| Income taxes | | | 36,915 | | | | 28,118 | | | | 36,249 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 63,841 | | | $ | 57,895 | | | $ | 58,921 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 63,841 | | | $ | 57,895 | | | $ | 58,921 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Reserve for regulatory adjustments | | | - | | | | (7,562 | ) | | | (363 | ) |
| Other regulatory charges - net | | | 44,807 | | | | 24,197 | | | | 16,808 | |
| Depreciation, amortization, and decommissioning | | | 74,035 | | | | 75,309 | | | | 68,345 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 4,365 | | | | (255 | ) | | | 218,873 | |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | 281,710 | | | | (35,081 | ) | | | (230,481 | ) |
| Fuel inventory | | | 2,688 | | | | (1,867 | ) | | | (10,939 | ) |
| Accounts payable | | | (99,483 | ) | | | 104,912 | | | | (1,328 | ) |
| Taxes accrued | | | 27,986 | | | | 33,842 | | | | 4,936 | |
| Interest accrued | | | 8,473 | | | | (5,947 | ) | | | 10,030 | |
| Deferred fuel costs | | | 123,927 | | | | (88,449 | ) | | | 21,619 | |
| Other working capital accounts | | | (95,603 | ) | | | 121,081 | | | | 86,598 | |
| Provision for estimated losses and reserves | | | (4,226 | ) | | | 4,073 | | | | (568 | ) |
| Changes in other regulatory assets | | | (187,250 | ) | | | (268,473 | ) | | | (21,038 | ) |
| Changes in pension and other postretirement liabilities | | | (12,594 | ) | | | 76,898 | | | | (6,901 | ) |
| Other | | | 54,857 | | | | (89,129 | ) | | | (38,521 | ) |
| Net cash flow provided by operating activities | | | 287,533 | | | | 1,444 | | | | 175,991 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (188,277 | ) | | | (283,622 | ) | | | (167,083 | ) |
| Allowance for equity funds used during construction | | | 5,232 | | | | 3,928 | | | | 3,295 | |
| Insurance proceeds | | | 36,749 | | | | 1,420 | | | | 5,244 | |
| Change in money pool receivable - net | | | (69,317 | ) | | | 154,176 | | | | (56,899 | ) |
| Collections received from (remitted to) transition charge account | | | (1,036 | ) | | | 7,211 | | | | (19,273 | ) |
| Net cash flow used in investing activities | | | (216,649 | ) | | | (116,887 | ) | | | (234,716 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 1,177,819 | | | | - | | | | 323,637 | |
| Return of capital to parent | | | - | | | | (150,000 | ) | | | - | |
| Retirement of long-term debt | | | (619,945 | ) | | | (327,514 | ) | | | (2,541 | ) |
| Change in money pool payable - net | | | (50,794 | ) | | | 50,794 | | | | - | |
| Loan from Entergy Corporation | | | - | | | | 160,000 | | | | - | |
| Repayment of loan from Entergy Corporation | | | (160,000 | ) | | | - | | | | - | |
| Changes in credit borrowings - net | | | (100,000 | ) | | | 100,000 | | | | - | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (119,500 | ) | | | (12,000 | ) | | | (42,404 | ) |
| Other | | | - | | | | (680 | ) | | | - | |
| Net cash flow provided by (used in) financing activities | | | 127,580 | | | | (179,400 | ) | | | 278,692 | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 198,464 | | | | (294,843 | ) | | | 219,967 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 2,239 | | | | 297,082 | | | | 77,115 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 200,703 | | | $ | 2,239 | | | $ | 297,082 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid/(received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 93,951 | | | $ | 82,635 | | | $ | 70,561 | |
| Income taxes | | $ | (72,322 | ) | | $ | 762 | | | $ | (1,930 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 1,552 | | | $ | 2,201 | |
| Temporary cash investments | | | 199,151 | | | | 38 | |
| Total cash and cash equivalents | | | 200,703 | | | | 2,239 | |
| Securitization recovery trust account | | | 13,098 | | | | 12,062 | |
| Accounts receivable: | | | | | | | | |
| Customer | | | 51,194 | | | | 82,583 | |
| Allowance for doubtful accounts | | | (844 | ) | | | (1,001 | ) |
| Associated companies | | | 75,437 | | | | 258,629 | |
| Other | | | 10,688 | | | | 14,122 | |
| Accrued unbilled revenues | | | 35,727 | | | | 30,262 | |
| Total accounts receivable | | | 172,202 | | | | 384,595 | |
| Deferred fuel costs | | | - | | | | 21,179 | |
| Accumulated deferred income taxes | | | 59,399 | | | | 88,611 | |
| Fuel inventory - at average cost | | | 54,957 | | | | 57,645 | |
| Materials and supplies - at average cost | | | 30,432 | | | | 36,329 | |
| Prepayments and other | | | 16,357 | | | | 12,785 | |
| TOTAL | | | 547,148 | | | | 615,445 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Investments in affiliates - at equity | | | 845 | | | | 845 | |
| Non-utility property - at cost (less accumulated depreciation) | | | 1,496 | | | | 1,788 | |
| Other | | | 16,309 | | | | 17,451 | |
| TOTAL | | | 18,650 | | | | 20,084 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,074,334 | | | | 2,912,972 | |
| Construction work in progress | | | 82,167 | | | | 221,387 | |
| TOTAL UTILITY PLANT | | | 3,156,501 | | | | 3,134,359 | |
| Less - accumulated depreciation and amortization | | | 1,210,172 | | | | 1,104,116 | |
| UTILITY PLANT - NET | | | 1,946,329 | | | | 2,030,243 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 95,894 | | | | 84,997 | |
| Other regulatory assets | | | 1,232,101 | | | | 1,117,257 | |
| Long-term receivables - associated companies | | | 34,340 | | | | 88,031 | |
| Other | | | 21,176 | | | | 28,714 | |
| TOTAL | | | 1,383,511 | | | | 1,318,999 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 3,895,638 | | | $ | 3,984,771 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND SHAREHOLDER'S EQUITY |
| | | | | | | | |
| | | December 31, |
| | | 2009 | | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing portion of debt assumption liability | | $ | 167,742 | | | $ | 100,509 | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 47,677 | | | | 144,662 | |
| Other | | | 70,147 | | | | 342,449 | |
| Customer deposits | | | 39,665 | | | | 40,589 | |
| Taxes accrued | | | 77,581 | | | | 49,595 | |
| Interest accrued | | | 30,575 | | | | 22,102 | |
| Deferred fuel costs | | | 102,748 | | | | - | |
| Pension and other postretirement liabilities | | | 935 | | | | 1,269 | |
| System agreement cost equalization | | | 117,204 | | | | 214,315 | |
| Other | | | 2,674 | | | | 4,551 | |
| TOTAL | | | 656,948 | | | | 920,041 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 740,074 | | | | 756,996 | |
| Accumulated deferred investment tax credits | | | 22,532 | | | | 24,128 | |
| Other regulatory liabilities | | | 20,417 | | | | - | |
| Asset retirement cost liabilities | | | 3,445 | | | | 3,250 | |
| Accumulated provisions | | | 8,710 | | | | 12,936 | |
| Pension and other postretirement liabilities | | | 78,722 | | | | 91,316 | |
| Note payable to Entergy Corporation | | | - | | | | 160,000 | |
| Long-term debt - assumption liability | | | - | | | | 669,462 | |
| Other long-term debt | | | 1,490,283 | | | | 414,906 | |
| Other | | | 30,017 | | | | 31,587 | |
| TOTAL | | | 2,394,200 | | | | 2,164,581 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| SHAREHOLDER'S EQUITY | | | | | | | | |
| Common stock, no par value, authorized 200,000,000 shares; | | | | | | | | |
| issued and outstanding 46,525,000 shares in 2009 and 2008 | | | 49,452 | | | | 49,452 | |
| Paid-in capital | | | 481,994 | | | | 481,994 | |
| Retained earnings | | | 313,044 | | | | 368,703 | |
| TOTAL | | | 844,490 | | | | 900,149 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 3,895,638 | | | $ | 3,984,771 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| CONSOLIDATED STATEMENTS OF RETAINED EARNINGS AND PAID-IN CAPITAL | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| RETAINED EARNINGS | | | | | | | | | |
| Retained Earnings - Beginning of period | | $ | 368,703 | | | $ | 322,808 | | | $ | 306,266 | |
| Add: | | | | | | | | | | | | |
| Net Income | | | 63,841 | | | | 57,895 | | | | 58,921 | |
| Total | | | 63,841 | | | | 57,895 | | | | 58,921 | |
| | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | |
| Dividends declared on common stock | | | 119,500 | | | | 12,000 | | | | 42,404 | |
| Other deductions | | | - | | | | - | | | | (25 | ) |
| Total | | | 119,500 | | | | 12,000 | | | | 42,379 | |
| | | | | | | | | | | | | |
| Retained Earnings - End of period | | $ | 313,044 | | | $ | 368,703 | | | $ | 322,808 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| PAID-IN CAPITAL | | | | | | | | | | | | |
| Paid-in Capital - Beginning of period | | $ | 481,994 | | | $ | 631,994 | | | $ | 632,222 | |
| | | | | | | | | | | | | |
| Add (Deduct): | | | | | | | | | | | | |
| Return of capital to parent | | | - | | | | (150,000 | ) | | | - | |
| Other | | | - | | | | - | | | | (228 | ) |
| | | | | | | | | | | | | |
| Paid-in Capital - End of period | | $ | 481,994 | | | $ | 481,994 | | | $ | 631,994 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | ENTERGY TEXAS, INC. AND SUBSIDIARIES | | | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (In Thousands) | | | (In Thousands) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 1,563,823 | | | $ | 2,012,258 | | | $ | 1,782,923 | | | $ | 1,880,228 | | | $ | 1,734,221 | | | $ | 1,581,496 | | | $ | 1,757,199 | | | $ | 1,690,431 | | | $ | 1,563,823 | | | $ | 2,012,258 | |
| Net Income | | $ | 63,841 | | | $ | 57,895 | | | $ | 58,921 | | | $ | 54,137 | | | $ | 48,916 | | | $ | 41,971 | | | $ | 80,845 | | | $ | 66,200 | | | $ | 63,841 | | | $ | 57,895 | |
| Total assets | | $ | 3,895,638 | | | $ | 3,984,771 | | | $ | 3,606,752 | | | $ | 3,019,873 | | | $ | 3,041,100 | | | $ | 4,025,781 | | | $ | 4,059,006 | | | $ | 3,783,864 | | | $ | 3,920,133 | | | $ | 3,984,771 | |
| Long-term obligations (1) | | $ | 1,490,283 | | | $ | 1,084,368 | | | $ | 1,103,863 | | | $ | 1,085,680 | | | $ | 1,085,593 | | | $ | 1,617,813 | | | $ | 1,677,127 | | | $ | 1,659,230 | | | $ | 1,490,283 | | | $ | 1,084,368 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) | (1) Includes long-term debt (excluding currently maturing debt) | | | | | | | | | | | | | | (1) Includes long-term debt (excluding currently maturing debt) | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | 2009 | | | | 2008 | | | | 2007 | | | | 2006 | | | | 2005 | | | | 2012 | | | | 2011 | | | | 2010 | | | | 2009 | | | | 2008 | |
| | | (Dollars In Millions) | | | (Dollars In Millions) | |
| Electric Operating Revenues: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Residential | | $ | 533 | | | $ | 606 | | | $ | 544 | | | $ | 600 | | | $ | 502 | | | $ | 553 | | | $ | 638 | | | $ | 559 | | | $ | 533 | | | $ | 606 | |
| Commercial | | | 337 | | | | 417 | | | | 364 | | | | 406 | | | | 327 | | | | 325 | | | | 369 | | | | 321 | | | | 337 | | | | 417 | |
| Industrial | | | 332 | | | | 489 | | | | 414 | | | | 464 | | | | 388 | | | | 299 | | | | 352 | | | | 305 | | | | 332 | | | | 489 | |
| Governmental | | | 23 | | | | 27 | | | | 24 | | | | 27 | | | | 22 | | | | 24 | | | | 26 | | | | 23 | | | | 23 | | | | 27 | |
| Total retail | | | 1,225 | | | | 1,539 | | | | 1,346 | | | | 1,497 | | | | 1,239 | | | | 1,201 | | | | 1,385 | | | | 1,208 | | | | 1,225 | | | | 1,539 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 294 | | | | 436 | | | | 398 | | | | 354 | | | | 468 | | | | 313 | | | | 262 | | | | 373 | | | | 294 | | | | 436 | |
| Non-associated companies | | | 10 | | | | 6 | | | | 6 | | | | 6 | | | | 6 | | | | 36 | | | | 74 | | | | 76 | | | | 10 | | | | 6 | |
| Other | | | 35 | | | | 31 | | | | 33 | | | | 23 | | | | 21 | | | | 31 | | | | 36 | | | | 33 | | | | 35 | | | | 31 | |
| Total | | $ | 1,564 | | | $ | 2,012 | | | $ | 1,783 | | | $ | 1,880 | | | $ | 1,734 | | | $ | 1,581 | | | $ | 1,757 | | | $ | 1,690 | | | $ | 1,564 | | | $ | 2,012 | |
| Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | �� | | | | Billed Electric Energy Sales (GWh): | | | | | | | | | | | | | | | | | |
| Residential | | | 5,453 | | | | 5,245 | | | | 5,280 | | | | 5,211 | | | | 5,207 | | | | 5,604 | | | | 6,034 | | | | 5,958 | | | | 5,453 | | | | 5,245 | |
| Commercial | | | 4,165 | | | | 4,092 | | | | 4,085 | | | | 4,002 | | | | 3,878 | | | | 4,396 | | | | 4,433 | | | | 4,271 | | | | 4,165 | | | | 4,092 | |
| Industrial | | | 5,570 | | | | 5,948 | | | | 5,911 | | | | 5,915 | | | | 5,650 | | | | 6,066 | | | | 6,102 | | | | 5,642 | | | | 5,570 | | | | 5,948 | |
| Governmental | | | 258 | | | | 248 | | | | 246 | | | | 255 | | | | 244 | | | | 278 | | | | 294 | | | | 271 | | | | 258 | | | | 248 | |
| Total retail | | | 15,446 | | | | 15,533 | | | | 15,522 | | | | 15,383 | | | | 14,979 | | | | 16,344 | | | | 16,863 | | | | 16,142 | | | | 15,446 | | | | 15,533 | |
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Associated companies | | | 3,630 | | | | 3,771 | | | | 4,366 | | | | 4,316 | | | | 4,994 | | | | 5,702 | | | | 4,158 | | | | 3,758 | | | | 3,630 | | | | 3,771 | |
| Non-associated companies | | | 231 | | | | 87 | | | | 89 | | | | 87 | | | | 89 | | | | 827 | | | | 1,258 | | | | 1,300 | | | | 231 | | | | 87 | |
| Total | | | 19,307 | | | | 19,391 | | | | 19,977 | | | | 19,786 | | | | 20,062 | | | | 22,873 | | | | 22,279 | | | | 21,200 | | | | 19,307 | | | | 19,391 | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | |
SYSTEM ENERGY RESOURCES, INC.
System Energy'sEnergy’s principal asset currently consists of a 90%an ownership interest and a leasehold interest in Grand Gulf. The capacity and energy from its 90% interest is sold under the Unit Power Sales Agreement to its only four customers, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. System Energy'sEnergy’s operating revenues are derived from the allocation of the capacity, energy, and related costs associated with its 90% interest in Grand Gulf pursuant to the Unit Power Sales Agreement. Payments under the Unit Power Sales Agreement are System Energy'sEnergy’s only source of operating revenues.
Results of Operations
Net Income
20092012 Compared to 20082011
Net income increased $47.7 million primarily due to increased operating income, higher other income, and a lower effective income tax rate. Operating income was higher because of higher rate base compared to 2011 resulting from the Grand Gulf uprate project. Other income was higher due to AFUDC accrued on the Grand Gulf uprate project. Grand Gulf’s spring 2012 refueling outage was completed in June 2012, and the majority of uprate-related capital improvements were completed during this outage.
2011 Compared to 2010
Net income decreased $42.2$18.4 million primarily due to an increase in the effective income tax rate.
An A decrease in operating income was offset by an increase in allowance for equity funds used during construction, primarily due to the new nuclear development project discussed below, was offset byother income and a decrease in interest income, primarily on money pool investments.
2008 Comparedexpense, which led to 2007
Net income decreased $45.0 million primarily due to ana slight increase in the effective tax rate, a decrease inincome before income taxes. Operating income was lower because of lower rate base in 2008 that resulted incompared to 2010. Other income was higher and interest expense was lower operating income, and lower interest income. The lower interest income resulted from a decrease in interest earnedprimarily because of AFUDC accrued on money pool investments and from $2.5 million in interest income recorded on an IRS audit settlement in 2007.the Grand Gulf uprate project.
Income Taxes
The effective income tax rates for 2009, 2008,2012, 2011, and 20072010 were 66.5%40.8%, 39.5%53.9%, and 25.0%40.4%, respectively. The increase in the rate for 20092011 is primarily due to an intercompany settle up for federal income taxes for years prior to 2008 which include an allocation of the reallocationtax benefit of Entergy Corporation consolidatedCorporation’s expenses to the subsidiaries generating taxable income for the respective years. The effects of various tax positions settled with the IRS pertaining to the 2006/2007 audit require System Energy to pay back prior benefits of the Entergy Corporation’s expenses it received when the benefits were originally allocated based onupon the resolution of IRS audits of prior tax years.return as filed. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35.0% to the effective income tax rate and for a discussion of the IRS audits.rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2009, 2008,2012, 2011, and 20072010 were as follows:follows.
| | | | 2009 | | 2008 | | 2007 | | 2012 | | | 2011 | | | 2010 | |
| | | | (In Thousands) | | (In Thousands) | |
| | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | Cash and cash equivalents at beginning of period | | $102,788 | | $105,005 | | $135,012 | | $ | 185,157 | | | $ | 263,772 | | | $ | 264,482 | |
| | | | | | | | | | | | | | | | | | | | |
| Cash flow provided by (used in): | | | | | | | |
| | Operating activities | | 417,877 | | 218,538 | | 221,901 | |
| | Investing activities | | (149,344) | | (96,954) | | (96,955) | |
| | Financing activities | | (106,839) | | (123,801) | | (154,953) | |
| | Net increase (decrease) in cash and cash equivalents | | 161,694 | | (2,217) | | (30,007) | |
| Net cash provided by (used in): | | | | | | | | | | | | | |
| Operating activities | | | | 412,000 | | | | 430,681 | | | | 250,405 | |
| Investing activities | | | | (502,637 | ) | | | (311,397 | ) | | | (184,588 | ) |
| Financing activities | | | | (10,898 | ) | | | (197,899 | ) | | | (66,527 | ) |
| Net decrease in cash and cash equivalents | | | | (101,535 | ) | | | (78,615 | ) | | | (710 | ) |
| | | | | | | | | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | Cash and cash equivalents at end of period | | $264,482 | | $102,788 | | $105,005 | | $ | 83,622 | | | $ | 185,157 | | | $ | 263,772 | |
System Energy Resources, Inc.
Management'sManagement’s Financial Discussion and Analysis
Operating Activities
Cash flow from operations increasedNet cash provided by $199.4operating activities decreased $18.7 million in 20092012 compared to 2011 primarily due to a decrease of $44.1 million in income tax refunds, partially offset by a decrease of $18.6 million in pension contributions. The income tax refunds of $56.8 million in 2012 resulted primarily from a decrease of previously estimated 2011 taxable income due to the recognition of additional bonus depreciation. See “Critical Accounting Estimates” below for a discussion of qualified pension and other postretirement benefits.
Net cash provided by operating activities increased $180.3 million in 2011 primarily due to income tax refunds of $120.4$100.9 million in 20092011 compared to income tax payments of $54.4$56 million in 2008.
Cash flow2010. In 2011, System Energy received cash refunds in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds result from operations decreased by $3.4 million in 2008 primarily due to lower net income substantially offset by a decrease in 2010 taxable income from what was previously estimated because of $30.7 millionthe recognition of additional repair expenses for tax purposes associated with a tax accounting change filed in income2010 and from the reversal of temporary differences for which System Energy previously made cash tax payments.
Investing Activities
Net cash flow used in investing activities increased $52.4$191.2 million in cash flow in 20092012 compared to 2011 primarily due to an increase in construction expenditures resulting from the uprate project at Grand Gulf and an increase of $94.3 million in nuclear fuel activity primarily due to the 2012 Grand Gulf refueling outage. The increase was partially offset by money pool activity.
Decreases in System Energy’s receivable from the money pool are a source of cash flow, and System Energy’s receivable from the money pool decreased $93.5 million in 2012 compared to increasing by $22.5 million in 2011. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Net cash used in investing activities increased $126.8 million in 2011 primarily due to:
| · | the proceeds from the transfer of $100.3 million in new nuclear development costs in the first quarter 2010. System Energy invested, through its subsidiary Entergy New Nuclear Development, LLC, in initial development costs for potential new nuclear development at the Grand Gulf and River Bend sites, including licensing and design activities. In the first quarter 2010, the construction work in progress incurred by Entergy New Nuclear Development, LLC was transferred to Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Mississippi; |
| · | an increase in construction expenditures resulting primarily from spending on the uprate project at Grand Gulf; |
| · | the repayment in 2010 of $25.6 million by Entergy New Orleans of a note issued in resolution of its bankruptcy proceedings; and |
The increase was partially offset by a decrease in nuclear fuel purchases due to the timing of refueling outages.
Increases in System Energy'sEnergy’s receivable from the money pool are a use of cash flow, and System Energy'sEnergy’s receivable from the money pool increased by $47.6$22.5 million in 20092011 compared to decreasingincreasing by $10.7$7.4 million in 2008. The money pool is an intercompany borrowing arrangement designed to reduce Entergy’s subsidiaries’ need for external short-term borrowings.2010.
Financing Activities
Net cash flow used in financing activities decreased $17.0$187 million in 20092012 compared to 2011 primarily due to a decreaseto:
| · | the issuance of $250 million of 4.10% Series first mortgage bonds in September 2012; |
| · | the issuance of $50 million of 4.02% Series H notes by the nuclear fuel company variable interest entity in February 2012; |
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
| · | an increase in borrowings of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2012 compared to the repayment of borrowings of $38.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011; |
| · | the redemption of $152.975 million of pollution control revenue bonds in 2012; |
| · | the redemption of $70 million of 6.2% Series first mortgage bonds in October 2012; and |
| · | the partial redemption of $40 million of 6.2% pollution control revenue bonds in 2011. |
Net cash flow used in financing activities decreased $31.2increased $131.4 million in 20082011 primarily due to the issuance of $60 million of 5.33% Series G notes by the nuclear fuel company variable interest entity in 2010, the repayment of borrowings of $38.3 million on the nuclear fuel company variable interest entity’s credit facility in 2011 compared to an increase in borrowings of $20.3 million on the nuclear fuel company variable interest entity’s credit facility in 2010, and the partial retirement of $40 million of 6.2% pollution control bonds in 2011. The increase was slightly offset by a $24.2 million decrease of $34 million in dividends paid on common stock dividends paid.stock.
See Note 5 to the financial statements for details of long-term debt.
Capital Structure
System Energy'sEnergy’s capitalization is balanced between equity and debt, as shown in the following table.
| | | December 31, 2009 | | December 31, 2008 | | December 31, 2012 | | December 31, 2011 |
| | | | | | | | | |
| Debt to capital | | | 48.5% | | 48.3% |
| Effect of subtracting cash | | | (2.8%) | | (7.1%) |
| Net debt to net capital | | 40.1% | | 48.2% | | 45.7% | | 41.2% |
| Effect of subtracting cash from debt | | 9.6% | | 3.0% | |
| Debt to capital | | 49.7% | | 51.2% | |
Net debt consists of debt less cash and cash equivalents. Debt consists of capital lease obligationsnotes payable and long-term debt, including the currently maturing portion. Capital consists of debt and common shareholder's equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the net debt to net capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy'sEnergy’s financial condition.
Uses of Capital
System Energy requires capital resources for:
| · | construction and other capital investments; |
| · | debt maturities;maturities or retirements; |
| · | working capital purposes, including the financing of fuel costs; and |
| · | dividend and interest payments. |
System Energy Resources, Inc.
Management's Financial Discussion and Analysis
Following are the amounts of System Energy'sEnergy’s planned construction and other capital investments, existing debt and lease obligations (includes estimated interest payments), and other purchase obligations:obligations.
| | 2010 | | 2011-2012 | | 2013-2014 | | After 2014 | | Total | |
| | (In Millions) |
| Planned construction and | | | | | | | | | | |
| capital investment | $170 | | $367 | | N/A | | N/A | | $537 | |
| Long-term debt (1) | $77 | | $226 | | $151 | | $660 | | $1,114 | |
| Nuclear fuel lease obligations (2) | $50 | | $25 | | N/A | | N/A | | $75 | |
| Purchase obligations (3) | $18 | | $22 | | $24 | | $79 | | $143 | |
| | 2013 | | 2014-2015 | | 2016-2017 | | After 2017 | | Total | |
| | (In Millions) |
| Planned construction and capital investment (1): | | | | | | | | |
| Generation | $21 | | $64 | | N/A | | N/A | | $85 | |
| Other | 2 | | 2 | | N/A | | N/A | | 4 | |
| Total | $23 | | $66 | | N/A | | N/A | | $89 | |
| Long-term debt (2) | $151 | | $218 | | $98 | | $574 | | $1,041 | |
| Purchase obligations (3) | $- | | $23 | | $24 | | $79 | | $126 | |
| (1) | Includes approximately $17 million annually for maintenance capital, which is planned spending on routine capital projects that are necessary to support reliability of service, equipment, or systems. The planned amounts do not include material costs for capital projects that might result from the NRC post-Fukushima requirements that remain under development. |
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
| (2) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
(2) | It is expected that additional financing under the lease will be arranged as needed to acquire additional fuel, to pay interest, and to pay maturing debt. If such additional financing cannot be arranged, however, System Energy must repurchase sufficient nuclear fuel to allow the lessor to meet its obligations. |
| (3) | Purchase obligations represent the minimum purchase obligation or cancellation charge for contractual obligations to purchase goods or services. For System Energy, it includes nuclear fuel purchase obligations. |
In addition to the contractual obligations given above, System Energy expects to contribute approximately $12.5$7.6 million to its pension plans and approximately $3.4$4.1 million to its other postretirement plans in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the2013. See "Critical Accounting Estimates – Qualified Pension Protection Actand Other Postretirement Benefits" below for a discussion of 2006 rules, effective for the 2008 plan yearqualified pension and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of System Energy’s pension contributions in the future.other postretirement benefits funding.
Also in addition to the contractual obligations, System Energy has $168.1$10.9 million of unrecognized tax benefits and interest net of unused tax attributes and payments for which the timing of payments beyond 12 months cannot be reasonably estimated due to uncertainties in the timing of effective settlement of tax positions. See Note 3 to the financial statements for additional information regarding unrecognized tax benefits.
The planned capital investment estimate for System Energy reflects capital required to support the existing business of System Energy. The estimate also includes the costs of System Energy's planned approximate 178 MW uprate of the Grand Gulf nuclear plant. The project is currently expected to cost $575 million, including transmission upgrades. On November 30, 2009, the MPSC issued a Certificate of Public Convenience and Necessity for implementation of the uprate.
System Energy has also invested, through its subsidiary Entergy New Nuclear Development, LLC, in initial development costs for potential new nuclear development at the Grand Gulf and River Bend sites, including licensing and design activities. This project is in the early stages, and several issues remain to be addressed over time before significant additional capital would be committed to this project. In addition, Entergy temporarily suspended reviews of the two license applications for the sites and will explore alternative nuclear technologies for this project. As of December 31, 2009, $100.3 million in construction work in progress was recorded on System Energy's balance sheet related to this project. In the first quarter 2010 this construction work in progress was transferred to Entergy Gulf States Louisiana, Entergy Louisiana, and Entergy Mississippi.
Entergy's Utility supply plan initiative will continue to seek to transform its generation portfolio with new or repowered generation resources. Opportunities resulting from the supply plan initiative, including new projects or the exploration of alternative financing sources, could result in increases or decreases in the capital expenditure estimates given above.
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy'sEnergy’s retained earnings are available for distribution.
System Energy Resources, Inc.
Management's Financial Discussion and Analysis
Sources of Capital
System Energy'sEnergy’s sources to meet its capital requirements include:
| · | internally generated funds; |
| · | bank financing under new or existing facilities. |
System Energy may refinance, redeem, or redeemotherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
All debt and common stock issuances by System Energy require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indentures and other agreements. System Energy has sufficient capacity under these tests to meet its foreseeable capital needs.
System Energy has obtained a short-term borrowing authorization from the FERC under which it may borrow, through October 2011,2013, up to the aggregate amount, at any one time outstanding, of $200 million. See Note 4 to the financial statements for further discussion of System Energy'sEnergy’s short-term borrowing limits. System Energy has also obtained an order from the FERC authorizing long-term securities issuances. The current long-term authorization extends through July 2011.2013. System Energy has obtained long-term financing authorization from the FERC that extends through November 2013 for issuances by its nuclear fuel company variable interest entity.
System Energy'sEnergy’s receivables from the money pool were as follows as of December 31 for each of the following years:.
| 2009 | | 2008 | | 2007 | | 2006 |
| (In Thousands) |
| | | | | | | |
| $90,507 | | $42,915 | | $53,620 | | $88,231 |
| 2012 | | 2011 | | 2010 | | 2009 |
| (In Thousands) |
| | | | | | | |
| $26,915 | | $120,424 | | $97,948 | | $90,507 |
In May 2007, $22.5 million of System Energy's receivable from the money pool was replaced by a note receivable from Entergy New Orleans. See Note 4 to the financial statements for a description of the money pool.
The System Energy nuclear fuel company variable interest entity has a credit facility in the amount of $100 million scheduled to expire in July 2013. As of December 31, 2012, $40 million was outstanding on the variable interest entity credit facility. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Nuclear Matters
System Energy owns and operates Grand Gulf. System Energy is, therefore, subject to the risks related to owning and operating a nuclear plant. These include risks from the use, storage, handling and disposal of high-level and low-level radioactive materials, regulatory requirement changes, including changes resulting from events at other plants, limitations on the amounts and types of insurance commercially available for losses in connection with nuclear operations, and technological and financial uncertainties related to decommissioning nuclear plants at the end of their licensed lives, including the sufficiency of funds in decommissioning trusts. In the event of an unanticipated early shutdown of Grand Gulf, System Energy may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Grand Gulf’s operating license is currently due to expire in November 2024. In October 2011, System Energy filed an application with the NRC for an extension of Grand Gulf’s operating license to 2045, which application is pending.
After the nuclear incident in Japan resulting from the March 2011 earthquake and tsunami, the NRC established a task force to conduct a review of processes and regulations relating to nuclear facilities in the United States. The task force issued a near-term (90-day) report in July 2011 that made initial recommendations, which were subsequently refined and prioritized after input from stakeholders. The task force then issued a second report in September 2011. Based upon the task force’s recommendations, the NRC issued three orders effective on March 12, 2012. The three orders require U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants. The NRC, with input from the industry, is in the process of determining the specific actions required by the orders and an estimate of the increased costs cannot be made at this time.
Environmental Risks
System Energy'sEnergy’s facilities and operations are subject to regulation by various governmental authorities having jurisdiction over air quality, water quality, control of toxic substances and hazardous and solid wastes, and other environmental matters. Management believes that System Energy is in substantial compliance with environmental regulations currently applicable to its facilities and operations. Because environmental regulations are subject to change, future compliance costs cannot be precisely estimated.
System Energy Resources, Inc.
Management's Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of System Energy'sEnergy’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that can have a significant effect on reported financial position, results of operations, and cash flows. Management has identified the following accounting policies and estimates as critical because they are based on assumptions and measurements that involve a high degree of uncertainty, and there is the potential for future changes in the assumptions and measurements that could produce estimates that would have a material impact on the presentation of System Energy'sEnergy’s financial position or results of operations.
Nuclear Decommissioning Costs
See "“Nuclear Decommissioning Costs"” in the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of the estimates inherent in accounting for nuclear decommissioning costs.
In the first quarter 2011, System Energy recorded a revision to its estimated decommissioning cost liability for Grand Gulf as a result of a revised decommissioning cost study. The revised estimate resulted in a $38.9 million reduction in its decommissioning liability, along with a corresponding reduction in the related regulatory asset.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified defined benefit pension plans which cover substantially all employees. Additionally, Entergy currently provides postretirement health care and life insurance benefits for substantially all employees who reach retirement age and meet certain eligibility requirements while still working for Entergy. Entergy'sEntergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are impacted by numerous factors including the provisions of the plans, changing employee demographics, and various actuarial calculations, assumptions, and accounting mechanisms. See the "“Critical Accounting Estimates"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for further discussion. Because of the complexity of these calculations, the long-term nature of these obligations, and the importance of the assumptions utilized, Entergy'sEntergy’s estimate of these costs is a critical accounting estimate.
Cost Sensitivity
The following chart reflects the sensitivity of qualified pension cost and qualified projected benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2012 Qualified Pension Cost | | Impact on Projected Qualified Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | (0.25%) | | $485 | | $4,806 | | (0.25%) | | $939 | | $10,978 |
| Rate of return on plan assets | | (0.25%) | | $326 | | - | | (0.25%) | | $483 | | $- |
| Rate of increase in compensation | | 0.25% | | $237 | | $1,282 | | 0.25% | | $375 | | $2,149 |
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands):.
Actuarial Assumption | | Change in Assumption | | Impact on 2009 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2012 Postretirement Benefit Cost | | Impact on Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | | | Increase/(Decrease) | | |
| | | | | | | | | | | | | |
| Discount rate | | | (0.25%) | | $360 | | $2,859 |
| Health care cost trend | | 0.25% | | $244 | | $1,248 | | 0.25% | | $490 | | $2,665 |
| Discount rate | | (0.25%) | | $175 | | $1,384 | |
Each fluctuation above assumes that the other components of the calculation are held constant.
System Energy Resources, Inc.
Management's Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for System Energy in 20092012 was $1.5$11.5 million. System Energy anticipates 20102013 qualified pension cost to be $1.9$11.9 million. System Energy contributed $4.8$9.8 million to its qualified pension plans in 20092012 and expects to contribute approximately $12.5$7.6 million in 20102013 although the required pension contributions will not be known with more certainty until the January 1, 20102013 valuations are completed by April 1, 2010. Also, guidance pursuant to the Pension Protection Act of 2006 rules, effective for the 2008 plan year and beyond, continues to evolve, be interpreted through technical corrections bills, and discussed within the industry and by congressional lawmakers. Any changes to the Pension Protection Act as a result of these discussions and efforts may affect the level of System Energy’s pension contributions in the future.2013.
Total postretirement health care and life insurance benefit costs for System Energy in 20092012 were $3.1$5.6 million, including $0.9$1.4 million in savings due to the estimated effect of future Medicare Part D subsidies. System Energy expects 20102013 postretirement health care and life insurance benefit costs to approximate $3.5$5.1 million, including $1.1$1.6 million in savings due to the estimated effect of future Medicare Part D subsidies. System Energy anticipates contributions forcontributed $6 million to its other postretirement health careplans in 2012 and life insurance benefits costsexpects to be $3.4contribute $4.1 million in 2010.2013.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Federal Healthcare Legislation
See the “Qualified Pension and Other Postretirement Benefits - Federal Healthcare Legislation” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of Federal Healthcare Legislation.
New Accounting Pronouncements
See "“New Accounting Pronouncements"” section of Entergy Corporation and Subsidiaries Management'sManagement’s Financial Discussion and Analysis for discussion of new accounting pronouncements.Analysis.
To the Board of Directors and Shareholder of
System Energy Resources, Inc.
Jackson, Mississippi
We have audited the accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 20092012 and 2008,2011, and the related income statements, statements of income, retained earnings, and cash flows, and statements of changes in common equity (pages 389404 through 394408 and applicable items in pages 6357 through 193)204) for each of the three years in the period ended December 31, 2009.2012. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits.
We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
In our opinion, such financial statements present fairly, in all material respects, the financial position of System Energy Resources, Inc. as of December 31, 20092012 and 2008,2011, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2009,2012, in conformity with accounting principles generally accepted in the United States of America.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the Company’s internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 24, 201027, 2013 expressed an unqualified opinion on the Company’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 2010
27, 2013
| SYSTEM ENERGY RESOURCES, INC. | |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 554,007 | | | $ | 528,998 | | | $ | 553,193 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 63,877 | | | | 44,506 | | | | 42,798 | |
| Nuclear refueling outage expenses | | | 19,186 | | | | 17,266 | | | | 16,699 | |
| Other operation and maintenance | | | 120,707 | | | | 120,165 | | | | 118,304 | |
| Decommissioning | | | 29,451 | | | | 27,642 | | | | 25,713 | |
| Taxes other than income taxes | | | 24,246 | | | | 15,896 | | | | 26,242 | |
| Depreciation and amortization | | | 140,056 | | | | 126,441 | | | | 122,765 | |
| Other regulatory credits - net | | | (17,525 | ) | | | (12,151 | ) | | | (8,854 | ) |
| TOTAL | | | 379,998 | | | | 339,765 | | | | 343,667 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 174,009 | | | | 189,233 | | | | 209,526 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 12,484 | | | | 4,910 | | | | 3,178 | |
| Interest and dividend income | | | 4,507 | | | | 12,086 | | | | 24,515 | |
| Miscellaneous - net | | | (1,813 | ) | | | (643 | ) | | | 382 | |
| TOTAL | | | 15,178 | | | | 16,353 | | | | 28,075 | |
| | | | | | | | | | | | | |
| INTEREST AND OTHER CHARGES | | | | | | | | | | | | |
| Interest on long-term debt | | | 47,422 | | | | 56,404 | | | | 56,966 | |
| Other interest - net | | | 148 | | | | 263 | | | | 151 | |
| Allowance for borrowed funds used during construction | | | (4,192 | ) | | | (1,642 | ) | | | (1,044 | ) |
| TOTAL | | | 43,378 | | | | 55,025 | | | | 56,073 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 145,809 | | | | 150,561 | | | | 181,528 | |
| | | | | | | | | | | | | |
| Income taxes | | | 96,901 | | | | 59,494 | | | | 45,447 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 48,908 | | | $ | 91,067 | | | $ | 136,081 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| |
| INCOME STATEMENTS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | |
| Electric | | $ | 622,118 | | | $ | 563,411 | | | $ | 558,584 | |
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | | | | | | | | | | | |
| Operation and Maintenance: | | | | | | | | | | | | |
| Fuel, fuel-related expenses, and | | | | | | | | | | | | |
| gas purchased for resale | | | 62,918 | | | | 76,353 | | | | 69,962 | |
| Nuclear refueling outage expenses | | | 21,824 | | | | 16,314 | | | | 17,398 | |
| Other operation and maintenance | | | 149,346 | | | | 136,495 | | | | 124,690 | |
| Decommissioning | | | 33,019 | | | | 31,460 | | | | 31,374 | |
| Taxes other than income taxes | | | 19,468 | | | | 21,425 | | | | 23,412 | |
| Depreciation and amortization | | | 154,561 | | | | 142,543 | | | | 138,641 | |
| Other regulatory credits - net | | | (10,429 | ) | | | (11,781 | ) | | | (12,040 | ) |
| TOTAL | | | 430,707 | | | | 412,809 | | | | 393,437 | |
| | | | | | | | | | | | | |
| OPERATING INCOME | | | 191,411 | | | | 150,602 | | | | 165,147 | |
| | | | | | | | | | | | | |
| OTHER INCOME | | | | | | | | | | | | |
| Allowance for equity funds used during construction | | | 26,102 | | | | 22,359 | | | | 9,892 | |
| Interest and investment income | | | 10,134 | | | | 8,294 | | | | 12,639 | |
| Miscellaneous - net | | | (617 | ) | | | (699 | ) | | | (518 | ) |
| TOTAL | | | 35,619 | | | | 29,954 | | | | 22,013 | |
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | | | | | | | | | | | |
| Interest expense | | | 45,214 | | | | 48,117 | | | | 51,912 | |
| Allowance for borrowed funds used during construction | | | (7,165 | ) | | | (6,711 | ) | | | (3,425 | ) |
| TOTAL | | | 38,049 | | | | 41,406 | | | | 48,487 | |
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | | 188,981 | | | | 139,150 | | | | 138,673 | |
| | | | | | | | | | | | | |
| Income taxes | | | 77,115 | | | | 74,953 | | | | 56,049 | |
| | | | | | | | | | | | | |
| NET INCOME | | $ | 111,866 | | | $ | 64,197 | | | $ | 82,624 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2012 | | | 2011 | | | 2010 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 111,866 | | | $ | 64,197 | | | $ | 82,624 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | | 235,881 | | | | 229,715 | | | | 219,552 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 43,651 | | | | 14,923 | | | | (1,536 | ) |
| Changes in assets and liabilities: | | | | | | | | | | | | |
| Receivables | | | (12,557 | ) | | | (5,512 | ) | | | (728 | ) |
| Accounts payable | | | (10,511 | ) | | | 17,275 | | | | (14,351 | ) |
| Prepaid taxes and taxes accrued | | | 89,022 | | | | 160,494 | | | | 1,327 | |
| Interest accrued | | | (2,157 | ) | | | (38,305 | ) | | | 3,503 | |
| Other working capital accounts | | | (22,917 | ) | | | 11,260 | | | | (15,287 | ) |
| Provisions for estimated losses | | | - | | | | - | | | | (2,009 | ) |
| Other regulatory assets | | | (44,004 | ) | | | 10,874 | | | | (4,948 | ) |
| Pension and other postretirement liabilities | | | 2,898 | | | | 34,474 | | | | 29,797 | |
| Other assets and liabilities | | | 20,828 | | | | (68,714 | ) | | | (47,539 | ) |
| Net cash flow provided by operating activities | | | 412,000 | | | | 430,681 | | | | 250,405 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (450,236 | ) | | | (234,753 | ) | | | (156,766 | ) |
| Proceeds from the transfer of development costs | | | - | | | | - | | | | 100,280 | |
| Allowance for equity funds used during construction | | | 26,102 | | | | 22,359 | | | | 9,892 | |
| Nuclear fuel purchases | | | (194,314 | ) | | | (59,755 | ) | | | (129,504 | ) |
| Proceeds from sale of nuclear fuel | | | 52,708 | | | | 12,420 | | | | - | |
| Changes in other investments | | | - | | | | - | | | | 25,560 | |
| Proceeds from nuclear decommissioning trust fund sales | | | 349,427 | | | | 203,444 | | | | 322,789 | |
| Investment in nuclear decommissioning trust funds | | | (379,833 | ) | | | (232,636 | ) | | | (349,398 | ) |
| Change in money pool receivable - net | | | 93,509 | | | | (22,476 | ) | | | (7,441 | ) |
| Net cash flow used in investing activities | | | (502,637 | ) | | | (311,397 | ) | | | (184,588 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | 297,908 | | | | - | | | | 55,385 | |
| Retirement of long-term debt | | | (262,867 | ) | | | (78,161 | ) | | | (41,715 | ) |
| Changes in credit borrowings - net | | | 39,986 | | | | (38,264 | ) | | | 20,003 | |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (79,700 | ) | | | (76,000 | ) | | | (100,200 | ) |
| Other | | | (6,225 | ) | | | (5,474 | ) | | | - | |
| Net cash flow used in financing activities | | | (10,898 | ) | | | (197,899 | ) | | | (66,527 | ) |
| | | | | | | | | | | | | |
| Net decrease in cash and cash equivalents | | | (101,535 | ) | | | (78,615 | ) | | | (710 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 185,157 | | | | 263,772 | | | | 264,482 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 83,622 | | | $ | 185,157 | | | $ | 263,772 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 34,012 | | | $ | 40,719 | | | $ | 35,540 | |
| Income taxes | | $ | (56,808 | ) | | $ | (100,889 | ) | | $ | 55,963 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 100 | | | $ | 30,961 | |
| Temporary cash investments | | | 83,522 | | | | 154,196 | |
| Total cash and cash equivalents | | | 83,622 | | | | 185,157 | |
| Accounts receivable: | | | | | | | | |
| Associated companies | | | 93,381 | | | | 172,943 | |
| Other | | | 5,904 | | | | 7,294 | |
| Total accounts receivable | | | 99,285 | | | | 180,237 | |
| Accumulated deferred income taxes | | | 74,331 | | | | - | |
| Materials and supplies - at average cost | | | 82,443 | | | | 86,333 | |
| Deferred nuclear refueling outage costs | | | 35,155 | | | | 9,479 | |
| Prepayments and other | | | 2,080 | | | | 1,111 | |
| TOTAL | | | 376,916 | | | | 462,317 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Decommissioning trust funds | | | 490,572 | | | | 423,409 | |
| TOTAL | | | 490,572 | | | | 423,409 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,987,672 | | | | 3,438,424 | |
| Property under capital lease | | | 569,355 | | | | 491,023 | |
| Construction work in progress | | | 40,392 | | | | 357,826 | |
| Nuclear fuel | | | 252,682 | | | | 157,967 | |
| TOTAL UTILITY PLANT | | | 4,850,101 | | | | 4,445,240 | |
| Less - accumulated depreciation and amortization | | | 2,568,862 | | | | 2,518,190 | |
| UTILITY PLANT - NET | | | 2,281,239 | | | | 1,927,050 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 126,503 | | | | 124,777 | |
| Other regulatory assets | | | 330,074 | | | | 287,796 | |
| Other | | | 18,212 | | | | 20,016 | |
| TOTAL | | | 474,789 | | | | 432,589 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 3,623,516 | | | $ | 3,245,365 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. | |
| BALANCE SHEETS | |
| LIABILITIES AND EQUITY | |
| | | | | | | |
| | | December 31, | |
| | | 2012 | | | 2011 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT LIABILITIES | | | | | | |
| Currently maturing long-term debt | | $ | 111,854 | | | $ | 110,163 | |
| Short-term borrowings | | | 39,986 | | | | - | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 5,564 | | | | 8,032 | |
| Other | | | 44,433 | | | | 63,331 | |
| Taxes accrued | | | 181,477 | | | | 92,455 | |
| Accumulated deferred income taxes | | | 1,789 | | | | 3,428 | |
| Interest accrued | | | 15,619 | | | | 17,776 | |
| Other | | | 2,429 | | | | 2,591 | |
| TOTAL | | | 403,151 | | | | 297,776 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 782,469 | | | | 652,418 | |
| Accumulated deferred investment tax credits | | | 56,188 | | | | 57,865 | |
| Other regulatory liabilities | | | 256,024 | | | | 214,745 | |
| Decommissioning | | | 478,371 | | | | 445,352 | |
| Pension and other postretirement liabilities | | | 142,617 | | | | 139,719 | |
| Long-term debt | | | 671,945 | | | | 636,885 | |
| Other | | | 22 | | | | 42 | |
| TOTAL | | | 2,387,636 | | | | 2,147,026 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| COMMON EQUITY | | | | | | | | |
| Common stock, no par value, authorized 1,000,000 shares; | | | | | | | | |
| issued and outstanding 789,350 shares in 2012 and 2011 | | | 789,350 | | | | 789,350 | |
| Retained earnings | | | 43,379 | | | | 11,213 | |
| TOTAL | | | 832,729 | | | | 800,563 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | | $ | 3,623,516 | | | $ | 3,245,365 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| |
| STATEMENTS OF CHANGES IN COMMON EQUITY | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| | | | | | | | | | |
| | | Common Equity | | | | |
| | | Common Stock | | | Retained Earnings | | | Total | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Balance at December 31, 2009 | | $ | 789,350 | | | $ | 40,592 | | | $ | 829,942 | |
| Net income | | | - | | | | 82,624 | | | | 82,624 | |
| Common stock dividends | | | - | | | | (100,200 | ) | | | (100,200 | ) |
| Balance at December 31, 2010 | | $ | 789,350 | | | $ | 23,016 | | | $ | 812,366 | |
| Net income | | | - | | | | 64,197 | | | | 64,197 | |
| Common stock dividends | | | - | | | | (76,000 | ) | | | (76,000 | ) |
| Balance at December 31, 2011 | | $ | 789,350 | | | $ | 11,213 | | | $ | 800,563 | |
| Net income | | | - | | | | 111,866 | | | | 111,866 | |
| Common stock dividends | | | - | | | | (79,700 | ) | | | (79,700 | ) |
| Balance at December 31, 2012 | | $ | 789,350 | | | $ | 43,379 | | | $ | 832,729 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
(Page left blank intentionally)
| |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2012 | | | 2011 | | | 2010 | | | 2009 | | | 2008 | |
| | | (Dollars In Thousands) | |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 622,118 | | | $ | 563,411 | | | $ | 558,584 | | | $ | 554,007 | | | $ | 528,998 | |
| Net Income | | $ | 111,866 | | | $ | 64,197 | | | $ | 82,624 | | | $ | 48,908 | | | $ | 91,067 | |
| Total assets | | $ | 3,623,516 | | | $ | 3,245,365 | | | $ | 3,224,070 | | | $ | 3,135,651 | | | $ | 2,945,390 | |
| Long-term obligations (1) | | $ | 671,945 | | | $ | 636,885 | | | $ | 796,728 | | | $ | 728,253 | | | $ | 832,697 | |
| Electric energy sales (GWh) | | | 6,602 | | | | 9,293 | | | | 8,692 | | | | 9,898 | | | | 8,475 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. | |
| STATEMENTS OF CASH FLOWS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | |
| Net income | | $ | 48,908 | | | $ | 91,067 | | | $ | 136,081 | |
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | |
| Other regulatory credits - net | | | (17,525 | ) | | | (12,151 | ) | | | (8,854 | ) |
| Depreciation, amortization, and decommissioning | | | 169,507 | | | | 154,083 | | | | 148,478 | |
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | | 211,297 | | | | 65,339 | | | | (37,827 | ) |
| Changes in working capital: | | | | | | | | | | | | |
| Receivables | | | (2,296 | ) | | | 11,621 | | | | (8,741 | ) |
| Accounts payable | | | 11,574 | | | | (146 | ) | | | 9,814 | |
| Preapaid taxes and taxes accrued | | | 5,413 | | | | (67,185 | ) | | | (47,988 | ) |
| Interest accrued | | | 2,667 | | | | 1,187 | | | | 1,268 | |
| Other working capital accounts | | | 11,672 | | | | (18,090 | ) | | | (23,841 | ) |
| Provision for estimated losses and reserves | | | (16 | ) | | | (444 | ) | | | 47 | |
| Changes in other regulatory assets | | | (4,824 | ) | | | (29,649 | ) | | | 15,250 | |
| Changes in pension and other postretirement liabilities | | | 3,440 | | | | 41,977 | | | | (2,029 | ) |
| Other | | | (21,940 | ) | | | (19,071 | ) | | | 40,243 | |
| Net cash flow provided by operating activities | | | 417,877 | | | | 218,538 | | | | 221,901 | |
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | | | | | | | | | | | |
| Construction expenditures | | | (90,778 | ) | | | (85,515 | ) | | | (84,108 | ) |
| Allowance for equity funds used during construction | | | 12,484 | | | | 4,910 | | | | 3,178 | |
| Nuclear fuel purchases | | | - | | | | (76,527 | ) | | | (56,264 | ) |
| Proceeds from sale/leaseback of nuclear fuel | | | 180 | | | | 76,530 | | | | 56,580 | |
| Proceeds from nuclear decommissioning trust fund sales | | | 392,959 | | | | 483,380 | | | | 105,751 | |
| Investment in nuclear decommissioning trust funds | | | (416,597 | ) | | | (510,437 | ) | | | (134,176 | ) |
| Change in money pool receivable - net | | | (47,592 | ) | | | 10,705 | | | | 12,084 | |
| Net cash flow used in investing activities | | | (149,344 | ) | | | (96,954 | ) | | | (96,955 | ) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of long-term debt | | | - | | | | - | | | | 69,482 | |
| Retirement of long-term debt | | | (28,440 | ) | | | (26,701 | ) | | | (93,335 | ) |
| Dividends paid: | | | | | | | | | | | | |
| Common stock | | | (75,300 | ) | | | (97,100 | ) | | | (131,100 | ) |
| Other | | | (3,099 | ) | | | - | | | | - | |
| Net cash flow used in financing activities | | | (106,839 | ) | | | (123,801 | ) | | | (154,953 | ) |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | | 161,694 | | | | (2,217 | ) | | | (30,007 | ) |
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | | 102,788 | | | | 105,005 | | | | 135,012 | |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | | $ | 264,482 | | | $ | 102,788 | | | $ | 105,005 | |
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | | | | | | | | | |
| Cash paid (received) during the period for: | | | | | | | | | | | | |
| Interest - net of amount capitalized | | $ | 39,611 | | | $ | 50,340 | | | $ | 50,437 | |
| Income taxes | | $ | (120,352 | ) | | $ | 54,436 | | | $ | 85,105 | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. | |
| BALANCE SHEETS | |
| ASSETS | |
| | | | | | | |
| | | December 31, | |
| | | 2009 | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | |
| CURRENT ASSETS | | | | | | |
| Cash and cash equivalents: | | | | | | |
| Cash | | $ | 926 | | | $ | 250 | |
| Temporary cash investments | | | 263,556 | | | | 102,538 | |
| Total cash and cash equivalents | | | 264,482 | | | | 102,788 | |
| Accounts receivable: | | | | | | | | |
| Associated companies | | | 139,602 | | | | 91,119 | |
| Other | | | 4,479 | | | | 3,074 | |
| Total accounts receivable | | | 144,081 | | | | 94,193 | |
| Note receivable - Entergy New Orleans | | | 25,560 | | | | - | |
| Materials and supplies - at average cost | | | 80,934 | | | | 74,496 | |
| Deferred nuclear refueling outage costs | | | 8,432 | | | | 26,485 | |
| Prepaid taxes | | | 69,366 | | | | 74,779 | |
| Prepayments and other | | | 936 | | | | 993 | |
| TOTAL | | | 593,791 | | | | 373,734 | |
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | | | | | | | |
| Decommissioning trust funds | | | 327,046 | | | | 268,822 | |
| Note receivable - Entergy New Orleans | | | - | | | | 25,560 | |
| TOTAL | | | 327,046 | | | | 294,382 | |
| | | | | | | | | |
| UTILITY PLANT | | | | | | | | |
| Electric | | | 3,324,876 | | | | 3,314,473 | |
| Property under capital lease | | | 481,065 | | | | 479,933 | |
| Construction work in progress | | | 198,887 | | | | 122,952 | |
| Nuclear fuel under capital lease | | | 75,438 | | | | 125,416 | |
| Nuclear fuel | | | 9,333 | | | | 7,448 | |
| TOTAL UTILITY PLANT | | | 4,089,599 | | | | 4,050,222 | |
| Less - accumulated depreciation and amortization | | | 2,315,141 | | | | 2,206,780 | |
| UTILITY PLANT - NET | | | 1,774,458 | | | | 1,843,442 | |
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | | | | | | | |
| Regulatory assets: | | | | | | | | |
| Regulatory asset for income taxes - net | | | 101,915 | | | | 89,473 | |
| Other regulatory assets | | | 290,048 | | | | 333,389 | |
| Other | | | 11,824 | | | | 10,970 | |
| TOTAL | | | 403,787 | | | | 433,832 | |
| | | | | | | | | |
| TOTAL ASSETS | | $ | 3,099,082 | | | $ | 2,945,390 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. |
| BALANCE SHEETS |
| LIABILITIES AND SHAREHOLDER'S EQUITY |
| | | | | | | | | |
| | | December 31, | |
| | | | 2009 | | | | 2008 | |
| | | (In Thousands) | |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | | $ | 41,715 | | | $ | 28,440 | |
| Accounts payable: | | | | | | | | |
| Associated companies | | | 5,349 | | | | 2,723 | |
| Other | | | 45,826 | | | | 35,215 | |
| Accumulated deferred income taxes | | | 3,040 | | | | 9,645 | |
| Interest accrued | | | 51,257 | | | | 48,590 | |
| Obligations under capital leases | | | 50,445 | | | | 37,619 | |
| TOTAL | | | 197,632 | | | | 162,232 | |
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | | | | | | | |
| Accumulated deferred income taxes and taxes accrued | | | 588,722 | | | | 365,134 | |
| Accumulated deferred investment tax credits | | | 58,231 | | | | 61,708 | |
| Obligations under capital leases | | | 24,993 | | | | 87,797 | |
| Other regulatory liabilities | | | 197,437 | | | | 197,051 | |
| Decommissioning | | | 421,408 | | | | 396,201 | |
| Accumulated provisions | | | 2,009 | | | | 2,025 | |
| Pension and other postretirement liabilities | | | 75,448 | | | | 72,008 | |
| Long-term debt | | | 703,260 | | | | 744,900 | |
| TOTAL | | | 2,071,508 | | | | 1,926,824 | |
| | | | | | | | | |
| Commitments and Contingencies | | | | | | | | |
| | | | | | | | | |
| SHAREHOLDER'S EQUITY | | | | | | | | |
| Common stock, no par value, authorized 1,000,000 shares; | | | | | |
| issued and outstanding 789,350 shares in 2009 and 2008 | | | 789,350 | | | | 789,350 | |
| Retained earnings | | | 40,592 | | | | 66,984 | |
| TOTAL | | | 829,942 | | | | 856,334 | |
| | | | | | | | | |
| TOTAL LIABILITIES AND SHAREHOLDER'S EQUITY | | $ | 3,099,082 | | | $ | 2,945,390 | |
| | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | |
| | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. | |
| STATEMENTS OF RETAINED EARNINGS | |
| | | | | | | | | | |
| | | For the Years Ended December 31, | |
| | | 2009 | | | 2008 | | | 2007 | |
| | | (In Thousands) | |
| | | | | | | | | | |
| Retained Earnings, January 1 | | $ | 66,984 | | | $ | 73,017 | | | $ | 68,036 | |
| | | | | | | | | | | | | |
| Add: | | | | | | | | | | | | |
| Net income | | | 48,908 | | | | 91,067 | | | | 136,081 | |
| | | | | | | | | | | | | |
| Deduct: | | | | | | | | | | | | |
| Dividends declared | | | 75,300 | | | | 97,100 | | | | 131,100 | |
| | | | | | | | | | | | | |
| Retained Earnings, December 31 | | $ | 40,592 | | | $ | 66,984 | | | $ | 73,017 | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| | | | | | | | | | | | | |
| SYSTEM ENERGY RESOURCES, INC. | |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | |
| | | | | | | | | | | | | | | | |
| | | 2009 | | | 2008 | | | 2007 | | | 2006 | | | 2005 | |
| | | (Dollars In Thousands) |
| | | | | | | | | | | | | | | | |
| Operating revenues | | $ | 554,007 | | | $ | 528,998 | | | $ | 553,193 | | | $ | 555,459 | | | $ | 533,929 | |
| Net Income | | $ | 48,908 | | | $ | 91,067 | | | $ | 136,081 | | | $ | 140,258 | | | $ | 111,644 | |
| Total assets | | $ | 3,099,082 | | | $ | 2,945,390 | | | $ | 2,858,760 | | | $ | 2,858,760 | | | $ | 3,046,039 | |
| Long-term obligations (1) | | $ | 728,253 | | | $ | 832,697 | | | $ | 824,824 | | | $ | 752,052 | | | $ | 882,949 | |
| Electric energy sales (GWh) | | | 9,898 | | | | 8,475 | | | | 8,440 | | | | 9,727 | | | | 9,070 | |
| | | | | | | | | | | | | | | | | | | | | |
| (1) Includes long-term debt (excluding currently maturing debt) and noncurrent capital lease obligations. | |
| | | | | | | | | | | | | | | | | | | | | |
Information regarding the registrant'sregistrant’s properties is included in Part I. Item 1. - Business under the sections titled "“Utility - Property and Other Generation Resources"” and "“Non-Utility NuclearEntergy Wholesale Commodities - Property"” in this report.
Details of the registrant'sregistrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 20092012 are discussed in Part I. Item 1. - Business under the sections titled "“Retail Rate Regulation"”, "“Environmental Regulation"”, and "“Litigation” and "Impairment of Long-Lived Assets" in Note 1 to the financial statements in this report.
During the fourth quarter of 2009, no matters were submitted to a vote of the security holders of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.Not applicable.
Executive Officers
| Name | Age | Position | | Period |
| | | | |
| Leo P. Denault (a)(b) | 53 | Chairman of the Board and Chief Executive Officer of Entergy Corporation | | 2013-Present |
| | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2004-2013 |
| | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, and System Energy | | 2004-2013 |
| | Director of Entergy Texas | | 2007-2013 |
| | Director of Entergy New Orleans | | 2011-2013 |
| | | | |
| J. Wayne Leonard (a)(b) | 5962 | Chairman of the Board of Entergy Corporation | | 2006-Present2006-2013 |
| | | Chief Executive Officer and Director of Entergy Corporation | | 1999-Present1999-2013 |
| | | | |
| William M. Mohl(a)(b) | | President, Entergy Wholesale Commodity Business of Entergy Corporation | | 2013-Present |
| | President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana | | 2010-2013 |
| | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2010-2013 |
| | Vice President, System Planning of Entergy Services, Inc. | | 2007-2010 |
| | | | | |
| Richard J. Smith (a)(b) | 5861 | President, Entergy Wholesale Commodity Business of Entergy Corporation | | 2010-2013 |
| | President and Chief Operating Officer of Entergy Corporation | | 2007-Present |
| | Group President, Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans | | 2001-2007 |
| | Director of Entergy Arkansas, Entergy Gulf States, Entergy Louisiana and Entergy Mississippi | | 2001-2007 |
| | Director of Entergy New Orleans | | 2001-20052007-2010 |
| | | | | |
Gary J. TaylorTheodore H. Bunting, Jr. (a) | 5654 | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi and Entergy Texas | | 2007-Present2012-Present |
| | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas | | 2007-Present2012-Present |
| | | Director of Entergy New Orleans | | 2008-Present |
| | ExecutiveSenior Vice President and Chief NuclearAccounting Officer of Entergy Corporation, | | 2004-2007 |
| | Director, President Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Chief Executive Officer of System Energy | | 2003-20072007-2012 |
| | | | | |
Leo P. DenaultAndrew S. Marsh (a)(b) | 5040 | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2004-Present2013-Present |
| | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy Texas and System Energy | | 2004-Present2013-Present |
| | | DirectorVice President, System Planning of Entergy TexasServices, Inc. | | 2007-Present2010-2013 |
| | | DirectorVice President, Planning and Financial Communications of Entergy New OrleansServices, Inc. | | 2004-2005 |
| | | | |
Curtis L. Hebert, Jr. (a) | 47 | Executive Vice President, External Affairs of Entergy Corporation | | 2001-Present |
| | | | |
John T. Herron (a) | 56 | President and Chief Executive Officer Nuclear Operations/ Chief Nuclear Officer of Entergy Corporation | | 2009-Present |
| | Senior Vice President, Nuclear Operations | | 2007-2009 |
| | Senior Vice President, Chief Operating Officer of Entergy Nuclear Northeast | | 2003-20072007-2010 |
| | | | | |
| Mark T. Savoff (a) | 5356 | Executive Vice President Operationsand Chief Operating Officer of Entergy Corporation | | 2004-Present2010-Present |
| | | Director of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Mississippi | | 2004-Present |
| | | Director of Entergy Texas | | 2007-Present |
| | | Director of Entergy New Orleans | | 2004-20052011-Present |
| | | Executive Vice President, Operations of Entergy Services, Inc.Corporation | | 2003-Present2004-2010 |
| | | | | |
Robert D. SloanRoderick K. West (a) | 6244 | Executive Vice President and Chief Administrative Officer of Entergy Corporation | | 2010-Present |
| | President and Chief Executive Officer of Entergy New Orleans | | 2007-2010 |
| | Director of Entergy New Orleans | | 2005-2011 |
| | | | |
| E. Renae Conley (a) | 55 | Executive Vice President, Human Resources and Administration of Entergy Corporation | | 2011-Present |
| | Executive Vice President of Entergy Corporation | | 2010-2011 |
| | President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana | | 2000-2010 |
| | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2000-2010 |
| | | | |
| Jeffrey S. Forbes(a)(c) | 56 | Executive Vice President, Nuclear Operations/Chief Nuclear Officer of Entergy Corporation | | 2013-Present |
| | Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States Louisiana and Entergy Louisiana | | 2013-Present |
| | President, Chief Executive Officer and Director of System Energy | | 2013-Present |
| | Senior Vice President, Nuclear Operations of Entergy Services, Inc. | | 2011-2013 |
| | Senior Vice President and Chief Operating Officer of Entergy Operations, Inc. | | 2003-2011 |
| | | | |
| John T. Herron (a)(c) | 59 | Nuclear Advisor | | 2013-Present |
| | President and Chief Executive Officer Nuclear Operations/ Chief Nuclear Officer of Entergy Corporation | | 2009-2013 |
| | Executive Vice President and Chief Nuclear Officer of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana and Entergy Texas | | 2010-2013 |
| | President, Chief Executive Officer and Director of System Energy | | 2009-2013 |
| | Senior Vice President, Nuclear Operations | | 2007-2009 |
| | | | |
| Marcus V. Brown (a) | 51 | Senior Vice President and General Counsel and Secretary of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy | | 2004-Present2012-Present |
| | | Executive Vice President and Deputy General Counsel and Secretary of Entergy TexasServices, Inc. | | 2007-Present2009-2012 |
| | Associate General Counsel of Entergy Services, Inc. | | 2007-2009 |
| | | | | |
Theodore H. Bunting, Jr.Alyson M. Mount (a) | 5142 | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and System Energy | | 2007-Present |
| | Acting principal financial officer of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas | | 2008-Present2012-Present |
| | | Vice President and Chief Financial Officer, Nuclear OperationsCorporate Controller of System EnergyEntergy Services, Inc. | | 2004-20072010-2012 |
| | | Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc. | | |
Terry R. Seamons (a) | 68 | Senior Vice President - Human Resources and Administration of Entergy Corporation | | 2007-Present |
| | Vice President and Managing Director of RHR, International | | 1984-20072002-2010 |
| | | | | |
| (a) | In addition, this officer is an executive officer and/or director of various other wholly owned subsidiaries of Entergy Corporation and its operating companies. |
| (b) | Mr. Leonard and Mr. Smith retired from the positions indicated effective January 31, 2013. Messrs. Denault, Marsh and Mohl assumed their new roles on February 1, 2013. |
| (c) | Mr. Herron resigned as President and Chief Executive Officer Nuclear Operations/Chief Nuclear Officer of Entergy Corporation effective January 2, 2013. He has advised Entergy that he intends to retire from his current position effective March 31, 2013. |
Each officer of Entergy Corporation is elected yearly by the Board of Directors.
PART II
Entergy Corporation
The shares of Entergy Corporation'sCorporation’s common stock are listed on the New York Stock and Chicago Stock Exchanges under the ticker symbol ETR.
The high and low prices of Entergy Corporation'sCorporation’s common stock for each quarterly period in 20092012 and 20082011 were as follows:
| | 2009 | | 2008 | 2012 | | 2011 |
| | High | | Low | | High | | Low | High | | Low | | High | | Low |
| | (In Dollars) | (In Dollars) |
| | | | | | | | | | | | | | | |
| First | 86.61 | | 59.87 | | 127.48 | | 99.45 | 73.66 | | 66.23 | | 74.50 | | 64.72 |
| Second | 78.78 | | 63.39 | | 123.27 | | 107.94 | 68.20 | | 62.97 | | 70.40 | | 65.15 |
| Third | 82.39 | | 71.76 | | 122.88 | | 83.78 | 74.50 | | 67.07 | | 69.14 | | 57.60 |
| Fourth | 84.44 | | 76.10 | | 89.76 | | 61.93 | 72.98 | | 61.55 | | 74.00 | | 62.66 |
Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 20092012 and 2008.2011. Quarterly dividends of $0.75$0.83 per share were paid in 20092012 and 2008.2011.
As of January 30, 2010,31, 2013, there were 38,48032,959 stockholders of record of Entergy Corporation.
Unregistered Sales of Equity Securities and Use of Proceeds
Issuer Purchases of Equity Securities (1)
| Period | | Total Number of Shares Purchased | | Average Price Paid per Share | | Total Number of Shares Purchased as Part of a Publicly Announced Plan | | Maximum $ Amount of Shares that May Yet be Purchased Under a Plan (2) |
| | | | | | | | | |
10/01/2009-10/2012-10/31/20092012 | | - | | $- | | - | | $750,000,000350,052,918 |
11/01/2009-11/2012-11/30/20092012 | | - | | $- | | - | | $750,000,000350,052,918 |
12/01/2009-12/2012-12/31/20092012 | | - | | $- | | - | | $750,000,000350,052,918 |
| Total | | - | | $- | | - | | |
(1) | In accordance with Entergy's stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy's common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy's management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In addition to this authority, on January 29, 2007, the Board approved a repurchase program under which Entergy is authorized to repurchase up to $1.5 billion of its common stock. In January 2008, the Board authorized an incrementalIn accordance with Entergy’s stock-based compensation plans, Entergy periodically grants stock options to key employees, which may be exercised to obtain shares of Entergy’s common stock. According to the plans, these shares can be newly issued shares, treasury stock, or shares purchased on the open market. Entergy’s management has been authorized by the Board to repurchase on the open market shares up to an amount sufficient to fund the exercise of grants under the plans. In October 2010 the Board granted authority for an additional $500 million share repurchase program to enable Entergy to consider opportunistic purchases in response to equity market conditions. In 2009, Entergy repurchased 7,680,000 shares of common stock under both programs for a total purchase price of $613 million. Entergy completed both the $1.5 billion and $500 million programs in the third quarter 2009. In October 2009 the Board granted authority for an additional $750 million share repurchase program. The amount of share repurchases under these programs may vary as a result of material changes in business results or capital spending or new investment opportunities. In addition, in the first quarter 2012, Entergy withheld 20,110 shares of its common stock at $70.62 per share to pay taxes due upon vesting of restricted stock granted as part of its long-term incentive program.
| (1) | See Note 12 to the financial statements for additional discussion of the stock-based compensation plans. |
| (2) | Maximum amount of shares that may yet be repurchased does not include an estimate of the amount of shares that may be purchased to fund the exercise of grants under the stock-based compensation plans. |
The amount of share repurchases may vary as a result of material changes in business results or capital spending or new investment opportunities.
Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common stock of Entergy Corporation'sCorporation’s wholly owned subsidiaries. Cash dividends on common stock paid by the Registrant Subsidiaries to Entergy Corporation during 20092012 and 2008,2011, were as follows:
| | | 2009 | | 2008 | | 2012 | | 2011 | | | | (In Millions) | | (In Millions) | | | | | | | | | | | | Entergy Arkansas | | $48.3 | | $24.9 | | $10.0 | | $117.8 | | Entergy Gulf States Louisiana | | $30.7 | | $104.2 | | $114.2 | | $302.0 | | Entergy Louisiana | | $20.6 | | $- | | $15.6 | | $358.2 | | Entergy Mississippi | | $51.3 | | $48.3 | | $- | | $3.3 | | Entergy New Orleans | | $32.9 | | $- | | $1.7 | | $42.0 | | Entergy Texas | | $119.5 | | $12.0 | | $87.2 | | $5.8 | | System Energy | | $75.3 | | $97.1 | | $79.7 | | $76.0 |
Information with respect to restrictions that limit the ability of the Registrant Subsidiaries to pay dividends is presented in Note 7 to the financial statements and in "statements.
Refer to “SELECTED FINANCIAL DISCUSSION AND ANALYSISDATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., AND SUBSIDIARIES, ENTERGY GULF STATES LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC., AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC."
Item 6. Selected Financial Data
Refer to "SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., ENTERGY GULF STATES LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC., and SYSTEM ENERGY RESOURCES, INC."” which follow each company'scompany’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.
Refer to "MANAGEMENT'S“MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC., AND SUBSIDIARIES, ENTERGY GULF STATES, LOUISIANA, L.L.C., ENTERGY LOUISIANA, LLC, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC., ENTERGY TEXAS, INC., AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC."”
Refer to "MANAGEMENT'S“MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments OF ENTERGY CORPORATION AND SUBSIDIARIES.".”
Refer to "“TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc."”
No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.
Disclosure Controls and Procedures
As of December 31, 2009,2012, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (each individually a "Registrant"(individually “Registrant” and collectively the "Registrants"“Registrants”) management, including their respective ChiefPrincipal Executive Officers (CEO)(PEO) and ChiefPrincipal Financial Officers (CFO)(PFO). The evaluations assessed the effectiveness of the Registrants'Registrants’ disclosure controls and procedures. Based on the evaluations, each CEOPEO and CFOPFO has concluded that, as to the Registrant or Registrants for which they serve as CEOPEO or CFO,PFO, the Registrant'sRegistrant’s or Registrants'Registrants’ disclosure controls and procedures are effective to ensure that information required to be disclosed by each Registrant in reports that it files or submits under the Securities Exchange Act of 1934 is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms; and that the Registrant'sRegistrant’s or Registrants'Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant'sRegistrant’s or Registrants'Registrants’ management, including their respective CEOsPEOs and CFOs,PFOs, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
(Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually "Registrant"“Registrant” and collectively the "Registrants"“Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant'sRegistrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant'sRegistrant’s financial statements presented in accordance with generally accepted accounting principles.
All internal control systems, no matter how well designed, have inherent limitations. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.
Each Registrant'sRegistrant’s management assessed the effectiveness of each Registrant'sRegistrant’s internal control over financial reporting as of December 31, 2009.2012. In making this assessment, each management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. Based on each management'smanagement’s assessment and the criteria set forth by COSO, each Registrant'sRegistrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2009.2012.
The Registrants'Registrants’ registered public accounting firm has issued an attestation report on each Registrant'sRegistrant’s internal control over financial reporting.
Changes in Internal ControlControls over Financial Reporting
Under the supervision and with the participation of the Registrants'each Registrant’s management, including theirits respective CEOsPEO and CFOs, the RegistrantsPFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 20092012 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Entergy Corporation and Subsidiaries New Orleans, Louisiana
We have audited the internal control over financial reporting of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 2009,2012, based on criteria established in Internal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Corporation’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Corporation’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Corporation maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control —Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20092012 of the Corporation and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those consolidated financial statements and included an explanatory paragraph relating to the adoption of a new accounting standard regarding non-controlling interests.statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Entergy Arkansas, Inc. and Subsidiaries Little Rock, Arkansas
We have audited the internal control over financial reporting of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of Entergy Gulf States Louisiana, L.L.C. Baton Rouge, Louisiana
We have audited the internal control over financial reporting of Entergy Gulf States Louisiana, L.L.C. (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of Entergy Louisiana, LLC and Subsidiaries Baton Rouge, Louisiana
We have audited the internal control over financial reporting of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Entergy Mississippi, Inc. Jackson, Mississippi
We have audited the internal control over financial reporting of Entergy Mississippi, Inc. (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of Entergy New Orleans, Inc. New Orleans, Louisiana
We have audited the internal control over financial reporting of Entergy New Orleans, Inc. (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of Entergy Texas, Inc. and Subsidiaries Beaumont, Texas
We have audited the internal control over financial reporting of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the consolidated financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of System Energy Resources, Inc. Jackson, Mississippi
We have audited the internal control over financial reporting of System Energy Resources, Inc. (the “Company”) as of December 31, 2009,2012, based on criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit.
We conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
A company’s internal control over financial reporting is a process designed by, or under the supervision of, the company’s principal executive and principal financial officers, or persons performing similar functions, and effected by the company’s board of directors, management, and other personnel to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of the inherent limitations of internal control over financial reporting, including the possibility of collusion or improper management override of controls, material misstatements due to error or fraud may not be prevented or detected on a timely basis. Also, projections of any evaluation of the effectiveness of the internal control over financial reporting to future periods are subject to the risk that the controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2009,2012, based on the criteria established in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the financial statements as of and for the year ended December 31, 20092012 of the Company and our report dated February 24, 201027, 2013 expressed an unqualified opinion on those financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana February 24, 201027, 2013
PART III
Information required by this item concerning directors of Entergy Corporation is set forth under the heading “Item 1 – Election of Directors” contained in the Proxy Statement of Entergy Corporation, to be filed in connection with its Annual Meeting of Stockholders to be held May 7, 2010,3, 2013, and is incorporated herein by reference.
All officers and directors listed below held the specified positions with their respective companies as of the date of filing this report, unless otherwise noted.
| Name | Age | Position | | Period | | | | | | | | ENTERGY ARKANSAS, INC. | | | | | | | | | | | Directors | | | | | | | | | | | | Hugh T. McDonald | 5154 | President and Chief Executive Officer of Entergy Arkansas | | 2000-Present | | | | Director of Entergy Arkansas | | 2000-Present | | | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | | | | | | | Officers | | | | | | | | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Curtis L. Hebert,Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | | | | | | | Officers | | | | | | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | E. Renae Conley | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | | | John T. Herron | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Hugh T. McDonald | | See information under the Entergy Arkansas Directors Section above. | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Terry R. Seamons | | See information under the Entergy Corporation Officers Section in Part I. | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | |
ENTERGY GULF STATES LOUISIANA, L.L.C. | | | | | | | | Directors | | | | | | | | | | E. Renae Conley | 52 | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2000-Present | | | President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana | | 2000-Present | | | | | | Leo P. DenaultAlyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. TaylorRoderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | | | | | | | | Directors | | | | | | | | | | | Phillip R. May, Jr. | 50 | Director of Entergy Gulf States Louisiana and Entergy Louisiana | | 2013-Present | | | President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana | | 2013-Present | | | Vice President, Regulatory Services of Entergy Services, Inc. | | 2002-2013 | | | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | William M. Mohl | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | | | | | |
| Officers | | | | | | | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | E. Renae Conley | | See information under the Entergy Gulf States Louisiana DirectorsCorporation Officers Section above.in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Curtis L. Hebert, Jr.Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | | | John T. Herron | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | Mark T. SavoffPhillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | Terry R. SeamonsWilliam M. Mohl | | See information under the Entergy Corporation Officers Section in Part I. | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | |
ENTERGY LOUISIANA, LLC | | | | | | | | Directors | | | | | | | | | | E. Renae Conley | | See information under the Entergy Gulf States Louisiana Directors Section above. | | | Leo P. DenaultAlyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. TaylorRoderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
| ENTERGY LOUISIANA, LLC | | | | | | | Directors | | | | | | | | | | | Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | William M. Mohl | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | | | | | | | | Officers | | | | | | | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | E. Renae Conley | | See information under the Entergy Gulf States Louisiana DirectorsCorporation Officers Section above.in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Curtis L. Hebert, Jr.Jeffrey S. Forbes | | See information under the Entergy Corporation Officers Section in Part I. | | | | John T. Herron | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | | Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | William M. Mohl | | See information under the Entergy Corporation Officers Section in Part I. | | | | Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Terry R. Seamons | | See information under the Entergy Corporation Officers Section in Part I. | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. TaylorRoderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
| ENTERGY MISSISSIPPI, INC. | | | | | | | | | | Directors | | | | | | | | | | | | Haley R. Fisackerly | 4447 | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present | | | | Director of Entergy Mississippi | | 2008-Present | | | | Vice President, Nuclear Government Affairs of Entergy Services, Inc. | | 2007-2008 | | | | Vice President, Customer Service of Entergy Mississippi | | 2002-2007 | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | |
| | | | | | Officers | | | | | | | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | E. Renae Conley | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Haley R. Fisackerly | | See information under the Entergy Mississippi Directors Section above. | | | Curtis L. Hebert, Jr.J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | John T. HerronAndrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | J. Wayne LeonardAlyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Terry R. Seamons | | See information under the Entergy Corporation Officers Section in Part I. | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. TaylorRoderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
| ENTERGY NEW ORLEANS, INC. | | | | | | | | | | Directors | | | | | | | | | | | Roderick K. WestCharles L. Rice, Jr. | 4148 | President and Chief Executive Officer of Entergy New Orleans | | 2007-Present2010-Present | | | | Director of Entergy New Orleans | | 2005-Present2010-Present | | | | Director, Metro Distribution OperationsUtility Strategy of Entergy Services, Inc. | | 2005-20062009-2010 | | | | Region Manager, Distribution OperationsLaw Partner in the firm of Entergy Services, Inc.Barrasso, Usdin, Kupperman, Freeman & Sarver, L.L.C. | | 2003-2005 | Sherri Winslow | 50 | Director of Entergy New Orleans | | 2008-Present | | | Vice President, Gas Distribution Business of Entergy Services, Inc. | | 2008-Present | | | Director, Employee Development of Entergy Services, Inc. | | 2006-2008 | | | Director, Customer Service Process Improvement of Entergy Services, Inc. | | 2006-2006 | | | | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | | | | | | | Officers | | | | | | | | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Curtis L. Hebert, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | John T. Herron | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | | Terry R. Seamons | | See information under the Entergy Corporation Officers Section in Part I. | | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | | | Roderick K. West | | See information under the Entergy New Orleans Directors Section above. | | | |
ENTERGY TEXAS, INC. | | | | | | | | Directors | | | | | | | | | | Joseph F. Domino | 61 | Director of Entergy Texas | | 2007-Present | | | President and Chief Executive Officer of Entergy Texas | | 2007-Present | | | Director of Entergy Gulf States | | 1999-2007 | | | President and Chief Executive Officer - TX of Entergy Gulf States | | 1998-2007 | | | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. Taylor | | See information under the Entergy Corporation Officers Section in Part I. | | |
| | | | | Officers | | | | 2005-2009 | | | | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | Joseph F. DominoMark T. Savoff | | See information under the Entergy Texas DirectorsCorporation Officers Section above.in Part I. | | |
| Officers | | | | | Curtis L. Hebert, | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | John T. HerronE. Renae Conley | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Charles L. Rice, Jr. | | See information under the Entergy New Orleans Directors Section above. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | Terry R. Seamons | | See information under the Entergy Corporation Officers Section in Part I. | | | Robert D. Sloan | | See information under the Entergy Corporation Officers Section in Part I. | | | Richard J. Smith | | See information under the Entergy Corporation Officers Section in Part I. | | | Gary J. TaylorRoderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
| ENTERGY TEXAS, INC. | | | | | | | Directors | | | | | | | | | | | Sallie T. Rainer | 51 | Director of Entergy Texas | | 2012-Present | | | President and Chief Executive Officer of Entergy Texas | | 2012-Present | | | Vice President, Federal Policy of Entergy Services, Inc. | | 2011-2012 | | | Director, Regulatory Affairs and Energy Settlements of Entergy Services, Inc. | | 2006-2011 | | | | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Officers | | | | | | | | | | | Marcus V. Brown | | See information under the Entergy Corporation Officers Section in Part I. | | | | Theodore H. Bunting, Jr. | | See information under the Entergy Corporation Officers Section in Part I. | | | | E. Renae Conley | | See information under the Entergy Corporation Officers Section in Part I. | | | | Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | | | J. Wayne Leonard | | See information under the Entergy Corporation Officers Section in Part I. | | | | Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | | | Alyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | | | Sallie T. Rainer | | See information under the Entergy Texas Directors Section above. | | | | Mark T. Savoff | | See information under the Entergy Corporation Officers Section in Part I. | | | | Roderick K. West | | See information under the Entergy Corporation Officers Section in Part I. | | |
Each director and officer of the applicable Entergy company is elected yearly to serve by the unanimous consent of the sole stockholder with the exception of the directors and officers of Entergy Gulf States Louisiana, L.L.C. and Entergy Louisiana, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owners, EGS Holdings, Inc. and Entergy Louisiana Holdings, respectively. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected at the annual meeting of the Board of Directors.
Corporate Governance Guidelines and Committee Charters
Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation'sCorporation’s Board of Directors operates under a written charter. In addition, the full Board has adopted Corporate Governance Guidelines. Each charter and the guidelines are available through Entergy'sEntergy’s website (www.entergy.com) or upon written request.
Audit Committee of the Entergy Corporation Board
The following directors are members of the Audit Committee of Entergy Corporation'sCorporation’s Board of Directors:
Steven V. Wilkinson (Chairman) Maureen S. Bateman Stuart L. Levenick James R. Nichols
Blanche L. Lincoln
All Audit Committee members are independent. For purposes of independence of members of the Audit Committee, an independent director also may not accept directly or indirectly any consulting, advisory, or other compensatory fee from Entergy or be affiliated with Entergy as defined in SEC rules. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. Steven V. Wilkinson qualifies as an "audit“audit committee financial expert,"” as that term is defined in the SEC rules.
Code of Ethics
The Board of Directors has adopted a Code of Business Conduct and Ethics for Members of the Board of Directors. The code is available through Entergy'sEntergy’s website (www.entergy.com) or upon written request. The Board has also adopted a Code of Business Conduct and Ethics for Employees that includes Special Provision Relating to Principal Executive Officer and Senior Financial Officers. The Code of Business Conduct and Ethics for Employees is to be read in conjunction with Entergy'sEntergy’s omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are required to abide by the Codes. Non-bargaining employees are required to acknowledge annually that they understand and abide by the Code of Entegrity. The Code of Business Conduct and Ethics for Employees and the Code of Entegrity are available through Entergy'sEntergy’s website (www.entergy.com) or upon written request.
Source of Nominations to the Board of Directors; Nominating Procedure
The Corporate Governance Committee has adopted a policy on consideration of potential director nominees. The Committee will consider nominees from a variety of sources, including nominees suggested by shareholders, executive officers, fellow board members, or a third party firm retained for that purpose. It applies the same procedures to all nominees regardless of the source of the nomination.
Any party wishing to make a nomination should provide a written resume of the proposed candidate, detailing relevant experience and qualifications, as well as a list of references. The Committee will review the resume and may contact references. It will decide based on the resume and references whether to proceed to a more detailed investigation. If the Committee determines that a more detailed investigation of the candidate is warranted, it will invite the candidate for a personal interview, conduct a background check on the candidate, and assess the ability of the candidate to provide any special skills or characteristics identified by the Committee or the Board.
Section 16(a) Beneficial Ownership Reporting Compliance
Information called for by this item concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement of Entergy Corporation to be filed in connection with its Annual Meeting of Stockholders to be held on May 7, 2010,3, 2013, under the heading "Section“Section 16(a) Beneficial Ownership Reporting Compliance"Compliance”, which information is incorporated herein by reference.
ENTERGY CORPORATION
Information concerning the directors and officers of Entergy Corporation is set forth in the Proxy Statement under the headings "Compensation Discussion and Analysis," "Executive Compensation Tables," "Nominees for the Board of Directors," and "Non-Employee Director Compensation," all of which information is incorporated herein by reference.
ENTERGY ARKANSAS, ENTERGY GULF STATES LOUISIANA, ENTERGY LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
Introduction
In this section, Entergy Corporation discusses and analyzes the salariescompensation earned by the following Named Executive Officers in 2012:
| Name | Title as of December 31, 2012 | | J. Wayne Leonard | Chairman of the Board and Chief Executive Officer | | Leo P. Denault | Executive Vice President and Chief Financial Officer | | Roderick K. West | Executive Vice President and Chief Administrative Officer | Theodore H. Bunting, Jr.1 | Group President, Utility Operations | Joseph F. Domino1 | Chief Integration Officer | | Haley R. Fisackerly | President, Entergy Mississippi | | Hugh T. McDonald | President, Entergy Arkansas | | William M. Mohl | President, Entergy Gulf States Louisiana and Entergy Louisiana | | Alyson M. Mount | Chief Accounting Officer (principal financial officer), Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | Sallie T. Rainer | President, Entergy Texas | | Charles L. Rice | President, Entergy New Orleans |
Mr. Leonard served and otherMr. Denault and Mr. West serve as executive officers of Entergy Corporation. No additional compensation elementswas paid in 20092012 to the ChiefMr. Leonard, Mr. Denault, or Mr. West for their service as Named Executive Officers ("CEOs"), the Principal Financial Officer ("PFO"), the three other most highly compensated executive officers other than the CEO and PFO (collectively, the "Named Executive Officers") of each of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas (the "Subsidiaries") are discussed and analyzed. The purpose of.
Entergy Corporation believes the executive pay programs described in this section is to provide investors with material information necessary to understand the compensation policies for the Named Executive Officers. This section should be read in combination with the more detailed compensation tables and other data presented elsewhere in this report. For information regarding the compensation of the named executive officers of Entergy Corporation, see the Proxy Statement of Entergy Corporation.
The Named Executive Officers are identified in the Summary Compensation Table immediately following this Compensation Discussionaccompanying tables have played a material role in the ability to drive strong financial and Analysis. Mr. Leonard, Mr. Denaultoperational results and Mr. Smith also serve as executive officers of Entergy Corporation. Mr. Leonard, Mr. Denaultto attract and Mr. Smith do not receive additional compensation for serving as Named Executive Officers of the Subsidiaries. For more information about the officers of the Subsidiaries, see Part III, Item 10 of this report.retain a highly experienced and successful management team.
Executive Summary Pay for Performance Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay-for-performance that is embodied in the design of the annual and long-term incentive plans. The compensation programannual incentive plan incentivizes and rewards the achievement of operational and financial metrics that are deemed by the Personnel Committee of the Entergy Corporation Board of Directors (the Personnel Committee) to be consistent with the overall goals and strategic direction that the Board has set for Entergy Corporation. The long-term incentive programs further align the interests of the executives and Entergy Corporation’s stockholders by directly tying the value of the equity awards granted to executives under these programs to the performance of Entergy Corporation’s stock price and total shareholder return in relation to its peers.
1 Mr. Bunting and Mr. Domino are included in the Executive Compensation section of this Form 10-K because Mr. Bunting served as Chief Accounting Officer (principal financial officer) of the Subsidiaries and Mr. Domino served as President, Entergy Texas for a portion of 2012. Application of Pay-for-Performance Philosophy
2012 Performance and Incentive Compensation
Pay outcomes for the Named Executive Officers has been designedduring 2012 demonstrated the application of Entergy Corporation’s pay-for-performance philosophy. Approximately 80% of the annual target compensation of Entergy Corporation’s Chief Executive Officer (excluding non-qualified supplemental retirement income) is “at risk” compensation, with the substantial majority of this “at risk” compensation consisting of awards under the Executive Annual Incentive Plan or Annual Incentive Plan and the Long-Term Performance Unit Program. Awards under the Annual Incentive Plan are tied to attract, retain, motivateEntergy Corporation’s operational and reward executives who can contributefinancial performance through the Entergy Achievement Multiplier, which is the performance metric used to determine the funding of awards under the Annual Incentive Plan. For 2012, the Entergy Achievement Multiplier was determined based in equal part on Entergy Corporation’s success in achieving the earnings per share and operating cash flow goals. These goals were set at the beginning of the year based on Entergy Corporation’s financial plan and the Board’s overall goals for Entergy Corporation and were consistent with its published earnings guidance. In January 2013, after taking into account special items related to the long-term successVermont Yankee impairment, the planned ITC Transaction, and thereby buildHurricane Isaac, the Personnel Committee determined that Entergy Corporation had exceeded its earnings per share goal, but had fallen short of its operating cash flow goal.
Despite strong operational performance in 2012, total shareholder return continued to fall below the Board’s expectations and the objectives of management. Under the Long-Term Performance Unit Program, a substantial portion of targeted executive officer pay is tied directly to total shareholder return. Under this program, performance is measured over a three-year period by assessing Entergy Corporation's total shareholder return in relation to the total shareholder return of the companies included in the Philadelphia Utility Index, with payouts based solely on relative performance. Performance is measured based on total shareholder return because it encourages the executives to deliver superior shareholder value in relation to Entergy Corporation’s peers and rewards not just stock price appreciation, but also the ability to deliver significant dividends to shareholders. Entergy Corporation’s total shareholder return for 2012 was in the bottom quartile of the Philadelphia Utility Index for the shareholders2010-2012 performance period, which resulted in a zero payout for the performance units granted in 2010. For additional information concerning the long-term compensation program, see “Long-Term Compensation - Performance Unit Program.” These results clearly demonstrate the strong linkage of pay to performance in Entergy Corporation.Corporation’s executive compensation programs.
2012 Significant Achievements
In addition to financial and operational results, Entergy Corporation’s Personnel Committee took into account the following significant achievements in its evaluation of 2012 performance. While certain of these accomplishments did not have a significant effect on 2012’s reported financial results, the Committee believes they have positioned Entergy Corporation well for future success:
| · | Successfully restored 92% of customers within 5 days after Hurricane Isaac (4th largest storm) vs. Gustav (8 days), Rita (13 days) and Katrina (16 days); |
| · | Restored 94% of customers within 5 days after the December 2012 winter storm in Arkansas; |
| · | Successfully implemented an executive succession plan for Entergy Corporation’s Chief Executive Officer, Chief Financial Officer, and other key executive positions; |
| · | Closed acquisitions of KGen Hinds and Hot Spring generating facilities; |
| · | Obtained 20-year license renewal from the Nuclear Regulatory Commission for Pilgrim Nuclear Station; |
| · | Successfully implemented the strategy to keep the Vermont Yankee nuclear plant operating beyond March 2012; |
| · | Obtained all regulatory approvals needed for six Entergy utility operating companies to move forward to join MISO; |
| · | Implemented a $1 billion commercial paper program, resulting in interest costs savings; |
| · | Successfully prepared for, responded to, and supported restoration for Hurricane Sandy; and |
| · | Received multiple awards and recognition for community relations, corporate citizenship, climate protection, and customer service. |
Executive Compensation Best Practices
The Personnel Committee, with the assistance of its independent executive compensation package is comprisedconsultant, engages in an ongoing review and evaluation of Entergy Corporation’s overall approach to its executive compensation programs to ensure that Entergy Corporation’s executive compensation programs continue to be in line with best practices of other companies in the industry as well as other Fortune 500 companies. As a result, Entergy Corporation:
| · | Has a recoupment or “clawback” policy. |
| · | Requires a “double trigger” to occur before any equity awards can vest upon a change in control. |
| · | Has a policy that prohibits hedging transactions in Entergy Corporation’s common stock. |
| · | Has a policy that prohibits pledging of Entergy Corporation’s common stock by directors and executive officers. |
| · | Caps the maximum payout under the Long-Term Performance Unit Program at 200% of target beginning with the 2011-2013 performance period, with no payout for performance below the third quartile of Entergy Corporation’s peer group. |
| · | Settles all awards under the Long-Term Performance Unit Program in shares of Entergy Corporation common stock, beginning with the 2012- 2014 performance period. |
| · | Requires executive officers to meet stock ownership guidelines. |
| · | Maintains the independence of Entergy Corporation’s independent compensation consultant. |
| · | Provides only a limited number of perquisites. |
Further, Entergy Corporation does not pay or provide any Named Executive Officer 280G “gross-up” payments in the case of a combinationchange in control. For additional information about the policies discussed above, see “Compensation Program Administration.”
2012 Changes Leadership Transition In September 2012, Entergy Corporation announced the retirement of short-termJ. Wayne Leonard as its Chairman and long-term compensation elements. Short-term compensation includesChief Executive Officer effective February 1, 2013. At that time, it was announced that Leo P. Denault would succeed Mr. Leonard as Chairman and Chief Executive Officer and that Andrew S. Marsh would succeed Mr. Denault as Executive Vice President and Chief Financial Officer. Mr. Marsh was previously Vice President, System Planning.
When Mr. Denault assumed the position as Chief Executive Officer, his annual base paysalary was increased to $1,085,000 and his annual cash bonus awards. Long-term compensation includes stock optionstarget under Entergy Corporation's Annual Incentive Plan was increased to 120% of base salary. Mr. Denault continues to participate in Entergy Corporation’s Long Term Performance Unit Program and performance units.
The executive compensation program is approved bycontinues to be eligible to receive awards under the Personnel Committee2011 Equity Ownership and Long-Term Cash Incentive Plan of Entergy Corporation which is comprised entirelyand Subsidiaries or “2011 Equity Ownership Plan.” The Committee determined the compensation level for Mr. Denault using competitive compensation data provided by its independent compensation consultant. It also considered his current compensation level and positioned the compensation for him below market rates with the intent of independent board members.transitioning him to competitive levels over time. Upon his retirement, Mr. Leonard did not receive any additional compensation from Entergy Corporation other than retirement benefits that will be paid in accordance with his retention agreement entered into at the time Mr. Leonard commenced employment with Entergy Corporation.
Also effective February 1, 2013, William M. Mohl assumed the position of President, Entergy Wholesale Commodity Business from Richard J. Smith who retired from that position. Mr. Mohl previously served as President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana. Phillip R. May succeeded Mr. Mohl as President and Chief Executive Officer of Entergy Gulf States Louisiana and Entergy Louisiana on February 1, 2013. Other leadership changes that occurred in 2012 included Alyson M. Mount succeeding Theodore H. Bunting, Jr. as Chief Accounting Officer of Entergy Corporation and the Subsidiaries and Sallie T. Rainer becoming President, Entergy Texas on May 31, 2012. Ms. Rainer replaced Joseph F. Domino who became Entergy Corporation’s Chief Integration Officer for the ITC Transaction. Ms. Mount assumed the position of Chief Accounting Officer, effective May 31, 2012, when Mr. Bunting became Entergy Corporation’s Group President, Utility Operations. Except where noted, throughout this Compensation Discussion and Analysis and in the compensation tables that follow, the title of each Named Executive Officer referred to is the title in effect on the last day of fiscal year 2012. Annual Incentive Plan Changes
Previously, once the Annual Incentive Plan performance goals established by the Personnel Committee were satisfied, a feature of the Annual Incentive Plan automatically increased the Entergy Achievement Multiplier by 25% for the members of the Office of the Chief Executive. The Personnel Committee then had the discretion to reduce or eliminate this 25% enhancement to the Entergy Achievement Multiplier for these officers altogether. This feature of the Annual Incentive Plan was intended to provide the Committee with a mechanism to take into consideration specific achievement factors relating to the overall performance of Entergy Corporation in accordance with Section 162(m) of the Code. In December 2012 the Committee eliminated this automatic increase in the Entergy Achievement Multiplier for members of the Office of the Chief Executive from the Annual Incentive Plan for future awards, reflecting the Personnel Committee’s determination that use of the Entergy Achievement Multiplier, in and of itself and without this automatic enhancement, was more consistent with the goals of the Annual Incentive Plan.
Results of 2012 Advisory Vote on Executive Compensation
As part of its ongoing review of Entergy Corporation’s executive compensation programs, the Personnel Committee also considered in 2012, and will consider in the future, the results of the advisory vote of Entergy Corporation’s shareholders on executive compensation. Given the approximately 98% level of support for Entergy Corporation’s executive compensation programs at its 2012 Annual Meeting and the input Entergy Corporation received through outreach to its institutional shareholders, the Committee believes that Entergy Corporation’s shareholders are very satisfied with Entergy Corporation’s executive compensation pay practices. As a result, the Personnel Committee did not make any changes to Entergy Corporation’s executive compensation programs in response to this advisory vote. However, the Personnel Committee did make the changes to the executive compensation programs as discussed above in connection with its ongoing review of Entergy Corporation’s executive compensation programs.
Establishing Executive Compensation
Executive Compensation Program Design
The following table summarizesexecutive compensation programs include three basic elements: base salary; annual cash incentives delivered through the principal factors that are taken into account in decidingAnnual Incentive Plan; and long-term equity compensation delivered through the amount of eachLong-Term Performance Unit Program, stock options, and restricted stock grants. Using these three elements, Entergy Corporation has sought to design the executive compensation element paid or awardedprograms to the executives:ensure that: Key Compensation Components
(where reported in summary
| ● | The compensation table) | Factors | Base Salary
(salary, column, c)
| -Entergy Corporation, business unitprograms enable us to attract, retain, and individual performance
-Market data
-Internal pay equity
-The Committee's assessment of other elements ofmotivate executive talent by offering competitive compensation
| Non-Equity Incentive Plan
Compensation
(non-equity plan compensation, column g)
| -Compensation practices at the peer group companies and the general market for
companies Entergy Corporation's size
-Desire to ensure that a substantial portion of total compensation is performance-based
-The Committee's assessment of other elements of compensation
-Entergy Corporation and individual performance
| Performance Units
(stock awards, column e)
| -Compensation practices at Entergy peer group companies and in broader group of
utility companies
-Target long-term compensation values in the market for similar jobs
-The desire to ensure that a substantial portion of total compensation is performance-
based
-The Committee's assessment of other elements of compensation
| Stock Options
(options, column f)
| -Individual performance
-Prevailing market practice
-Targeted long-term value created by the use of stock options
-Potential dilutive effect of stock option grants
-The Committee's assessment of other elements of compensation
packages. |
Compensation decisions for each executive officer are made after taking into account all elements
Objectives of the Executive Compensation Program
· | ● | The greatest part of the compensation of the Named Executive Officers should beOfficers’ compensation is in the form of "at risk" performance-based compensation.compensation, in order to focus the executives on the achievement of superior results and align compensation with shareholder value. |
The compensation programs are designed to ensure that a significant percentage of the total compensation of the Named Executive Officers is contingent on achievement of performance goals that drive total shareholder return and result in increases in Entergy Corporation's common stock price. For example, each of the annual cash incentive and long-term performance unit programs is designed to pay out if Entergy Corporation achieves pre-established performance goals. Assuming achievement of these performance goals at target level, approximately 80% of the annual target total compensation (excluding non-qualified supplemental retirement income) of Entergy Corporation's Chief Executive Officer is represented by performance-based compensation and the remaining 20% is represented by base salary. For Mr. Denault and Mr. Smith, assuming achievement of performance goals at the target levels, approximately 65% of the annual target total compensation (excluding non-qualified supplemental retirement income) is represented by performance-based compensation and the remaining 35% by base salary. For substantially all of the other Named Executive Officers, assuming achievement of performance goals at the target levels, at
least 50% of the annual target total compensation (excluding non-qualified supplemental retirement income) is represented by performance-based compensation and the remaining 50% by base salary. Entergy Corporation's Chief Executive Officer's total compensation is at greater risk than the other Named Executive Officers, reflecting both market practice and acknowledging the leadership role of the Chief Executive Officer in setting company policy and strategies.
· | ● | A substantial portion of the Named Executive Officers' compensation should beis delivered in the form of equity awards.awards, which are required to be retained until stock ownership targets are met. |
To align the economic interests of the Named Executive Officers with the shareholders of Entergy Corporation, Entergy Corporation believes a substantial portionthis philosophy has enabled us to closely align executive compensation with corporate performance and shareholder value, while at the same time attracting and retaining the highest caliber of their total compensation should be in the form of equity-based awards. Awards are typically granted in the form of stock options with a three-year vesting schedule and performance units with a three-year performance cycle. Stock options are generally subject only to time-based vesting. Performance units pay out only if Entergy Corporation achieves specified performance targets. The amount of payout depends on the level of performance achieved.executive talent.
· | The compensation programs of Entergy Corporation and the Subsidiaries should enable the companies to attract, retain and motivate executive talent by offering compensation packages that are competitive but fair. |
It is in the shareholders' best interests that Entergy Corporation and the Subsidiaries attract and retain talented executives by offering compensation packages that are competitive, but fair. Entergy Corporation's Personnel Committee has sought to develop compensation programs that deliver total target compensation in aggregate at approximately the 50th percentile of the market.
The Starting Point
To develop a competitive compensation program, the Personnel Committee on an annual basisannually reviews base salary and other compensation data from two sources:
· | Survey Data: The Committee uses published and private compensation survey data to develop marketplace compensation levels for executive officers. The data, which is compiled by the Committee's independent compensation consultant, compares the current compensation levels received by each of the executive officers against the compensation levels received by executives holding similar positions at companies with corporate revenues consistent with the revenues of Entergy Corporation. For non-industry specific positions such as a chief financial officer, the Committee reviews general industry data.Survey Data
The Committee uses published and private compensation survey data to develop marketplace compensation levels for the executive officers. The data, which is compiled by the Committee’s independent compensation consultant, compares the current compensation opportunities provided to each of the executive officers against the compensation opportunities provided to executives holding similar positions at companies with corporate revenues similar to Entergy Corporation’s. For non-industry specific positions such as a chief financial officer, the Committee reviews general industry data for total cash compensation (base salary and annual incentive). For management positions that are industry-specific such as Group President, Utility Operations, the Committee reviews data from utility companies for total cash compensation. However, for long-term incentives, all positions are reviewed relative to utility market data. The survey data reviewed by the Committee covers hundreds of companies across a broad range of industries and over 60 investor-owned utility companies in the utility sector. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are industry-specific such as Group President, Utility Operations, the Committee reviews data from energy services companies. The survey data reviewed by the Committee covers approximately 300 public and private companies in general industry and approximately 70 public and private companies in the energy services sector. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identity of the companies comprising the survey data is not disclosed to, or considered by, the Committee in its decision-making process and, thus, is not considered material by the Committee. |
The Committee uses the survey data to develop compensation programsopportunities that deliver total target compensation at approximately the 50th percentile of the surveyed companies. This survey data is used as the primary data for purposes of determining target compensation. For this purpose, the Committee reviews the results of the survey data (organized in tabular format) comparing each of the Named Executive Officer's compensation relative to the 25th, 50th (or median) and 75th percentile of the surveyed companies. The Committee considers its objectives to have been met if Entergy Corporation'sCorporation’s Chief Executive Officer and the eight (8) other executive officers of Entergy Corporation who constitute what is referred to as the Office of the Chief Executive considered as a group (9 officers including Mr. Denault and Mr. Smith) and the other Named Executive Officerseach have a target compensation packageopportunity that falls within the range of 90 - 110 percent85% – 115% of the 50th percentile of the surveyed companies. In 2009, in the aggregate the target compensation of all of the Named Executive Officers fell within this range.survey data. Actual compensation received by an individual officer may be above or below the 50th percentile based on an individual officer'sofficer’s skills, performance, experience and responsibilities, company performance, and internal pay equity. In 2012 the target compensation for the Named Executive Officers did not exceed 115% of the 50th percentile of the survey data.
Proxy Analysis
Although the survey data described above is the primary data used in determining compensation, the Committee reviews data derived from proxy statements as an additional point of comparison. The proxy data is used to compare the compensation levels of the Named Executive Officers with the compensation levels of the corresponding top five highest paid executive officers of the companies included in the Philadelphia Utility Index, as reported in their proxy statements, based on pay rank and without regard to roles and responsibilities. The Personnel Committee uses this analysis to evaluate the overall reasonableness of Entergy Corporation’s compensation programs. The following companies were included in the Philadelphia Utility Index at the time the proxy data was compiled:
· | Proxy Analysis: Although the survey data described above is the primary data source used in determining compensation, the Committee reviews data derived from proxy statements as an additional point of analysis. The proxy data is used to compare the compensation levels of executive officers against the compensation levels of the corresponding executive officers from 18 of the companies included in the Philadelphia Utilities Index. The analysis is used by the Committee to evaluate the reasonableness of the Company’s compensation program. The proxy market data compare Entergy executive officers to other proxy officers based on pay rank without regard to roles and responsibilities. These companies are:
|
· AES Corporation | · Exelon CorporationEl Paso International | · Ameren Corporation | · FirstEnergyExelon Corporation | · American Electric Power Co. Inc. | · FPL Group Inc.FirstEnergy Corporation | · CenterPoint Energy Inc. | · Northeast UtilitiesNextEra Energy | · Consolidated Edison Inc. | · PG&ENortheast Utilities | ·Covanta Holding Corporation | ·PGE Corporation | · Dominion Resources Inc. | ·Progress Energy, Inc.
| ·DTE Energy Company
| · Public Service Enterprise Group, Inc. | · DukeDTE Energy CorporationCompany | · Southern Company | · Edison InternationalDuke Energy Corporation | · XCELXcel Energy | ·Edison International | |
ElementsFactors Used to Determine Compensation
When determining each compensation element for executive officers, the Personnel Committee in the case of Mr. Leonard, Mr. Denault, and Mr. West, and in the case of the Compensation Program
The major componentsother Named Executive Officers, their supervisors, consider some or all of the executive compensation program are presented below:
Short-Term Compensationfollowing factors:
| · | Base SalaryAnalysis provided by the Committee's independent compensation consultant of compensation practices at industry peer group companies and the general market for comparable positions in companies Entergy Corporation’s size; |
| · | Competitiveness of Entergy's executive compensation programs and Entergy Corporation’s ability to attract and retain top executive talent; |
| · | Individual performance of each Named Executive Officer; |
| · | The desire to ensure that a substantial portion of total compensation is performance-based; |
| · | The relative importance of the short-term performance goals established pursuant to the Annual Incentive Plan; |
| · | Internal pay equity and the executive pay structure; |
| · | The Committee's assessment of other elements of compensation provided to the Named Executive Officer; and |
| · | The Chief Executive Officer’s recommendations, for all Named Executive Officers other than himself. |
Mr. Leonard, Entergy Corporation’s Chief Executive Officer, received a higher compensation level compared to the other Named Executive Officers to reflect the following factors:
| · | Market practices that compensate chief executive officers at greater potential compensation levels with more “pay at risk” than other named executive officers; and |
| · | The Personnel Committee’s assessment of Mr. Leonard’s strong performance based on the Board’s annual performance evaluation, in which the Board reviews and assesses Mr. Leonard’s performance based on critical factors such as: leadership, strategic planning, financial results, succession planning, communications with Entergy Corporation’s stakeholders, external relations with the communities and industries in which Entergy Corporation operates and his relationship with the Board. |
Executive Compensation Elements
Short-Term Compensation
Base Salary
Pay data is analyzed and used to determine the base salaries for all of the Named Executive Officers. Base salary is a component of eachthe Named Executive Officer'sOfficers’ compensation package because the Committee believes it is appropriate that some portion of the compensation that is provided to these officers be provided in a form that is a fixed cash amount.stable. Also, base salary remains the most common form of payment throughout all industries. Itsindustries and its use ensures a competitive compensation package tofor the Named Executive Officers.
The Committee (in the case of Mr. Leonard, Mr. Denault and Mr. Smith) or certain senior Entergy officers (in the case of the other Named Executive Officers) determine whether to award Named Executive Officers annual merit increases in base salary based on the following factors:
· | Entergy Corporation, business unit and individual performance during the prior year; |
· | Internal pay equity; and |
· | The Committee's assessment of other elements of compensation provided to the Named Executive Officer. |
The corporate and business unit goals and objectives vary by individual officers and include, among other things, corporate and business unit financial performance, capital expenditures, cost containment, safety, reliability, customer service, business development and regulatory matters.
The use of "internal“internal pay equity"equity” in setting merit increases is limited toassists us in determining whether a change in an executive officer'sofficer’s role and responsibilities relative to other executive officers requires an adjustment into the officer'sofficer’s salary. The Committee, however, has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.
In January 2009,2012, all of the Named Executive Officers received merit increases in their base salaries in the range of 2 to 3 percent, except for Mr. Bunting, Ms. Mount, and Ms. Rainer. The increases in base salary were made in light of current economic conditions and the projected slow growth in executive officer salaries in 20092012 based on Entergy’s review of general industry surveys prepared by variousobtained from human resourceresources consulting firms, as well as, an internal pay equity comparison. Upon assuming the Personnel Committee decided notposition of Chief Accounting Officer of Entergy and the Subsidiaries, Ms. Mount’s base salary increased 27% to increase the 2009$280,000, Ms. Rainer’s base salary was increased 22% to $275,000 when she became President, Entergy Texas, and Mr. Bunting’s base salary was increased 52% to $560,000 when he became Group President, Utility Operations. Their salaries of the executive officers who constitute the Office of the Chief Executive from the 2008 base salaries.
In addition,were increased to reflect their new roles and responsibilities and was based on the results of this study,internal pay equity and market information provided by the 2009 base salaries for Ms. Conley, Mr. Domino, Mr. Fisackerly, Mr. McDonaldPersonnel Committee’s independent compensation consultant.
The following table sets forth the 2011 and Mr. West were not increased. Ms. Conley, Mr. Domino, Mr. Fisackerly, Mr. McDonald and Mr. West, however, received a cash bonus in lieu of an increase in their base salary. See “2009 Summary Compensation Table” for the amount of the bonus paid to each of these officers. Mr. Bunting received a 2.5% merit increase to his 2008 base salary to reflect comparative market data for senior accounting officers. The 20092012 base salaries for the Named Executive Officers were:Officers. Changes in base salaries were effective in April of each of the years shown, except for Mr. Bunting, Ms. Mount, and Ms. Rainer whose salaries were effective on the date of their promotion in 2012.
Named Executive
Officer
| 2009 Base Salary
| J. Wayne Leonard | $1,291,500 | Leo P. Denault | $630,000 | Richard J. Smith | $645,000 | E. Renae Conley | $407,680 | Hugh T. McDonald | $322,132 | Joseph F. Domino | $317,754 | Roderick K. West | $315,000 | Theodore H. Bunting | $350,447 | Haley Fisackerly | $275,000 |
| Named Executive Officer | 2011 Base Salary | 2012 Base Salary | | | | | | J. Wayne Leonard | $1,323,800 | $1,350,276 | | Leo P. Denault | $ 655,200 | $ 674,856 | | Roderick K. West | $ 572,000 | $ 589,160 | | Theodore H. Bunting, Jr. | $ 359,212 | $ 560,000 | | Joseph F. Domino | $ 324,104 | $ 330,550 | | Haley R. Fisackerly | $ 283,250 | $ 288,950 | | Hugh T. McDonald | $ 330,185 | $ 336,800 | | William M. Mohl | $ 335,550 | $ 342,250 | | Alyson M. Mount | $ 214,712 | $ 280,000 | | Sallie T. Rainer | $ 220,629 | $ 275,000 | | Charles L. Rice | $ 247,200 | $ 252,100 |
· | Non-EquityAnnual Incentive Plan (Cash Bonus) |
Performance-based incentives are included in the Named Executive Officers'Officers’ compensation packages because it encouragesEntergy Corporation believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall goals and strategic direction that the Entergy boardBoard has set for Entergy Corporation. Annual incentive plans are commonly used by companies in a variety of industry sectors to compensate their executive officers.officers for achieving financial and operational goals. The Named Executive Officers participate in a performance-based cash bonus plan known asUnder the Executive Annual Incentive Plan, or Executive Incentive Plan. The Executive Incentive Plan operates onEntergy Corporation uses a calendar year basis. A performance metric known as the Entergy Achievement Multiplier is used to determine the payouts for each particular calendar year. The Entergy Achievement Multiplier is used to determine the percentage of target annual plan awardsopportunities that will be paid each year to each Named Executive Officer. In December 2008,Officer, subject to adjustment based on individual performance.
Each year the Personnel Committee selectedreviews the performance measures forused to determine the Entergy Achievement MultiplierMultiplier. In December 2011 the Personnel Committee decided to be based in equal part onretain for 2012 the performance measures used for determining the 2011 Entergy Achievement Multiplier. These measures were consolidated earnings per share and operating cash flow, for 2009 awards.with each measure weighted equally. The Committee selected these performance measures because:
| · | earnings per share and operating cash flow have both a correlative and causal relationship towith shareholder value performance;over the long-term; |
| · | earnings per share and operating cash flow targets are aligned with externally-communicated goals; and |
| · | earnings per share and operating cash flow results are readily available in earning releases and SEC filings. |
In addition, these measures are commonly used by a number of other companies, including the industry peer group companies in the Philadelphia Utility Index, as components of their incentive programs. For example, approximately 56 percent70% of the industry peer group companies use earnings per share as an incentive measure and 22 percent use some type of cash flow measure. The Personnel Committee evaluates and sets the performance measures used for the Executive Incentive Plan and the Management Incentive Plan on an annual basis.
The Committee sets minimum, target, and maximum achievement levels under the ExecutiveAnnual Incentive Plan. There is no payout for performance at or below the minimum achievement level, the payout for performance at target is 100% of the target payout, and the payout for performance at or above the maximum achievement level is 200% of target. Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight linestraight-line interpolation. In general, the Committee seeks to establish target achievement levels such that the relative difficulty of achieving the target level is consistent from year to year. Over the past five years ending with 2009,2012, the average Entergy Achievement Multiplier was 128%132% of target.
In December 2008,2011, the Committee set the 20092012 target awardsaward for incentives to be paid in 2010for 2012 under the Annual Incentive Plan for Entergy Corporation’s Chief Executive Incentive Plan. As a percentageOfficer at 120% of his base salary the target awards for certain of Entergy named executive officers were set as follows: J. Wayne Leonard, CEO of Entergy Corporation (120%); Leo P. Denault, Executive Vice President and Chief Financial Officer (70%); and Richard J. Smith, President and Chief Operating Officer of Entergy Corporation (70%). The Committee based its decision on the target awards for Mr. Denault and Mr. Smith on the recommendationWest at 70% of Entergy’s Chief Executive Officer.
In setting these target awards, the Personnel Committee considered several factors, including:
· | Analysis provided by the Committee's independent compensation consultant as to compensation practices at the industry peer group companies and the general market for companies the size of Entergy Corporation; |
· | Competitiveness of Entergy Corporation's compensation plans and their ability to attract and retain top executive talent; |
· | The individual performance of each Entergy named executive officer (other than the Chief Executive Officer of Entergy Corporation) as evaluated by the Chief Executive Officer of Entergy Corporation; |
· | Target bonus levels in the market for comparable positions; |
· | The desire to ensure that a substantial portion of total compensation is performance-based; |
· | The relative importance, in any given year, of the short-term performance goals established pursuant to the Executive Incentive Plan; and |
· | The Committee's assessment of other elements of compensation provided to the Entergy named executive officers. |
their respective base salaries. The target awards for the other Named Executive Officers were set as follows: E. Renae Conley, CEO - Entergy Gulf States Louisiana and CEO - - Entergy Louisiana (60%Theodore H. Bunting, Jr. (70%); Joseph F. Domino CEO - Entergy Texas (50%); Haley Fisackerly (40%); Hugh T. McDonald CEO - Entergy Arkansas (50%); Roderick K. West, CEO - Entergy New OrleansWilliam M. Mohl (60%); Alyson M. Mount, (60%); Sallie T. Rainer (40%); Haley Fisackerly, CEO - Entergy Mississippiand Charles L. Rice, Jr. (40%) and Theodore H. Bunting – Principal Accounting Officer – the Subsidiaries (60%).
The target awards for the Named Executive Officers (other than Entergy Corporation named executive officers) were set by their respective supervisors (subject to ultimate approval of Entergy’s Corporation Chief Executive Officer) who allocated a potential incentive pool established by the Personnel Committee among various of their direct and indirect reports. In setting the target awards, the supervisor took into account considerations similar to those used by the Personnel Committee in setting the target awards for Entergy’s Named Executive Officers. The Committee established a higher target percentage for Mr. Leonard compared to the other Named Executive Officers to reflect the following factors:
· | Mr. Leonard's leadership and contributions to Entergy Corporation's success as measured by, among other things, the overall performance of Entergy Corporation. |
· | Market practices that compensate chief executive officers at greater potential compensation levels with more "pay at risk" than other executive officers. |
· | The Personnel Committee's assessment of Mr. Leonard's strong performance based on the Board's annual performance evaluation, in which the Board reviews and assesses Mr. Leonard's performance based on: leadership, strategic planning, financial results, succession planning, communications with all of the stakeholders, external relations with the communities and industries in which Entergy Corporation operates and his relationship with the Board. |
Target awards are set based on an executive officer’s current position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 thoroughthrough Level 4. At December 31, 2012, Mr. Bunting, Mr. Denault, and Mr. Smith holdWest held positions in Level 2, whereasMs. Mount and Mr. Bunting and Ms. Conley holdMohl held positions in Level 3 and Mr. Domino, Mr. Fisackerly, Mr. McDonald and Mr. West holdthe remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive targets differ one from another based on the external market data developed by the Committee’s independent compensation consultant and the other factors noted above.
In January 2009,2012, the Committee determined the Entergy Achievement MultiplierAnnual Incentive Plan targets to be used for purposes of establishingdetermining annual bonuses for 2009.2012. The Committee’s determination of the target levels was made after full Board review of management’s 2012 financial plan for the Entergy System companies, upon recommendation of the Finance Committee, and after the Committee’s determination that the established targets aligned with Entergy Corporation’s anticipated 2012 financial performance as reflected in the financial plan and Entergy Corporation’s published earnings guidance. In keeping with past practice with respect to known special items that would be excluded from operational earnings, the Committee also determined, based on the recommendation of the Finance Committee, that for purposes of measuring performance against such targets, an adjustment would be made to exclude the effect on as-reported results of activities associated with Entergy Corporation’s planned ITC Transaction (considered a special item). The Committee therefore established to measurethe following targets for purposes of measuring management performance against asas-reported results, adjusted to exclude the effect on reported results excluding the impact of activities associated with the planned separationITC Transaction. | | Minimum | Target | Maximum | | Earnings Per Share ($) | $5.22 | $5.80 | $6.38 | | Operating Cash Flow ($ billion) | $2.840 | $3.240 | $3.640 |
| | Minimum | Target | Maximum | | Earnings Per Share ($) | 6.30 | 7.00 | 7.70 | Operating Cash Flow ($ in Billions) | 2.52 | 2.88 | 3.24 |
After reviewingIn January 2013, the Committee and full Board reviewed Entergy Corporation’s as-reported and operational earnings per share and operating cash flow results against the established performance objectives reflected in the above table and,table. The Committee noted that in 2012, Entergy Corporation’s as-reported results included, in addition to the special item for costs associated with the proposed ITC Transaction, a special item for an asset impairment taken in accordance with generally accepted accounting principles in connection with the Vermont Yankee nuclear plant and triggered by state actions to shut down the plant. Both of these special items were excluded from Entergy Corporation’s as-reported earnings per share and operating cash flow for purposes of measuring performance against the previously established targets. Regarding the Vermont Yankee impairment, certain benefits to operational earnings resulting from the impairment, such as reduced depreciation expense, also were excluded. In making the determination to exclude the effect of the Vermont Yankee impairment, the Committee took into account not only the fact that it was a special item not included in operational earnings, but also management’s performance in formulating and executing Entergy Corporation’s strategy with respect to Vermont Yankee.
The Committee also considered the impact on as-reported and operational earnings and operating cash flow of certain costs incurred in connection with Hurricane Isaac, which struck the Entergy System service territory in late August 2012 and left more than 787,000 customers without power, making it the fourth-most significant storm in Entergy System’s history in terms of outages. The Committee specifically noted the Executive Incentive Plan, adjusting for non-recurring charges for impairmentsunusual pressure on Entergy System personnel to restore these outages quickly, due to the nuclear decommissioning trust,large number of customers who sheltered in place, and the Entergy System’s outstanding performance in that regard. In light of this performance, the Committee, based on the recommendation of the Finance Committee and the full Board of Directors, adjusted as-reported results to exclude not only the special items noted above, but also the effects of Hurricane Isaac for purposes of measuring management’s performance against the targets set in January 2010,2012 and determining the Entergy Achievement Multiplier. This adjustment had a negligible effect on earnings per share, but increased operating cash flow significantly to reflect the cash expended in the restoration effort. This was consistent with the Committee’s view that in general, management’s performance for such purposes should be measured against operational results, subject to adjustment in appropriate circumstances for unusual or extraordinary events or performance.
The Personnel Committee determined that after taking into account the adjustments noted above, Entergy Corporation had exceeded its earnings per share goal, but had fallen short of its operating cash flow goal. Based on this review and the recommendation of the Finance Committee and the Board of Directors, in January 2013, the Personnel Committee therefore certified the 20092012 Entergy Achievement Multiplier at 115%104% of target. This determination was subsequently ratified by the full Board of Directors.
Under the terms of the Annual Incentive Plan’s Management Effectiveness Program, the 2012 Entergy Achievement Multiplier iswas automatically increased by 25 percent25% for the members of the Office of the Chief Executive, (including Mr. Leonard, Mr. Denault and Mr. Smith, but not the other Named Executive Officers), subject to the Personnel Committee'sCommittee’s discretion to adjust the automatic multiplier downwardreduce or eliminate itthe increase altogether. In accordance with Section 162(m) ofJanuary 2013 the Internal Revenue Code, the multiplier which Entergy refers to asCommittee eliminated the Management Effectiveness Factor is intended to provide the Committee, through the exercise of negative discretion, a mechanism to take into consideration the specific achievement factors relating to the overall performance of Entergy Corporation. In January 2010, the Committee exercised its negative discretion to eliminate the Management Effectiveness FactorProgram with respect to the 20092012 incentive awards, reflecting the Personnel Committee'sCommittee’s determination that the Entergy Achievement Multiplier, in and of itself without the Management Effectiveness Factor, was consistent with the performance levels achieved by management.
The annual incentiveEntergy Corporation’s management did not warrant application of this enhancement. After consultation with the Chief Executive Officer with respect to the other members of the Office of the Chief Executive and based on its evaluation of the performance of the Chief Executive Officer and other members of the Office of Chief Executive, the Committee applied an additional downward adjustment to the awards forto be paid to all of the Namedmembers of the Office of the Chief Executive, Officers (other thanincluding Mr. Leonard, Mr. Denault, Mr. Bunting, and Mr. Smith) are awardedWest which had the effect of reducing their awards from an104% of target to 95% of target. The Committee made this adjustment based on its determination that despite the many accomplishments of management in 2012 and strong operational performance, management had not fully met the Committee’s expectations with respect to Entergy Corporation’s safety performance.
After the Entergy Achievement Multiplier was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s current Chief Executive Officer, Mr. Denault, with input from Mr. Leonard, allocated incentive pool approved byaward funding to the Committee. From this pool, each named executive officer’s supervisor determinesbusiness units based on their business unit results (referred to as the annual incentive payment“line of business multiplier”). Individual awards were determined based on the Entergy Achievement Multiplier. The supervisor has the discretion to increase or decrease the multiple used to determine an incentive award based online of business multiplier as well as individual and business unit performance. The incentive awards are subject to the ultimate approval of Entergy’s Chief Executive Officer.officer performance.
The following table shows the Executive and ManagementAnnual Incentive PlansPlan payments as a percentage of base salary for 20092012, as well as the incentive awards forpaid to each Named Executive Officer:Officer for 2012: | Named Exeutive Officer | Target | Percentage Base Salary | 2009 Annual Incentive Award | | | Named Executive Officer | | Target as Percentage of Base Salary | Payout as Percentage of Base Salary | 2012 Annual Incentive Award | | J. Wayne Leonard | 120% | 138% | $1,782,270 | 120% | 114% | $1,539,315 | | Leo P. Denault | 70% | 81% | $ 507,150 | 70% | 66% | $ 448,779 | | Richard J. Smith | 70% | 81% | $ 519,225 | | | E. Renae Conley | 60% | 75% | $ 307,000 | | | Roderick K. West | | 70% | 66% | $ 391,791 | | Theodore H. Bunting, Jr. | | 70% | 66% | $ 372,400 | | Joseph F. Domino | | 50% | 50% | $ 165,000 | | Haley R. Fisackerly | | 40% | 48% | $ 139,000 | | Hugh T. McDonald | 50% | 40% | $ 128,066 | 50% | 60% | $ 202,000 | | Joseph F. Domino | 50% | 35% | $ 111,373 | | | Roderick K. West | 40% | 50% | $ 158,000 | | | Haley Fisackerly | 40% | 50% | $ 138,000 | | | Theodore H. Bunting | 60% | 96% | $ 335,000 | | | William M. Mohl | | 60% | 88% | $ 300,000 | | Alyson M. Mount | | 60% | 75% | $ 210,000 | | Sallie T. Rainer | | 40% | 47% | $ 128,000 | | Charles L. Rice | | 40% | 46% | $ 115,000 |
Long-Term Incentive Compensation
Entergy Corporation'sThe goal for long-term incentive programs are intendedcompensation is to focus and reward the Named Executive Officersexecutive officers for achievement ofbuilding shareholder value creation overand to increase the long-term.executive officers’ ownership in Entergy Corporation’s common stock. In itsthe long-term incentive compensation programs, Entergy Corporation primarily uses a mix of performance units, restricted stock, and stock options in order to accomplish different objectives.options. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock appreciation, and dividend payments, and stock price relative to the industry peer group companies.companies in the Philadelphia Utility Index. Restricted stock ties the executive officers’ long-term financial interest to the long-term financial interests of Entergy Corporation’s shareholders. Stock options provide a direct incentive for increasingto increase the price of Entergy Corporation common stock. In addition, Entergy Corporation occasionally awards restricted stock units for retention purposes or to offset forfeited compensation in order to attract officers and managers from other companies. The target value of long-term incentive compensation is allocated 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, all based on their grant date fair values.
EachAll of the performance units, shares of restricted stock, and stock options and restricted units granted to the Named Executive Officers in 20092012 were awarded under the 20072011 Equity Ownership Plan. All equity awards granted under the equity ownership plans require both a change in control and Long Term Cash Incentive Planan involuntary job loss or substantial diminution of Entergy Corporation, which is referred to asduties (a “double trigger”) for the 2007 Equity Ownership Plan.acceleration of these awards upon a change in control.
· | Performance Unit Program |
Entergy Corporation issues performance unit awards to the Named Executive Officers under itsthe Long-Term Performance Unit Program. Each Performance UnitHistorically, each performance unit equals the cash value of one share of Entergy Corporation common stock at the end of the three-year performance cycle.period. Each unit also earns the cash equivalent of the dividends paid during the performance cycle.period. Dividends accrued during the performance period are paid out only to the extent that the performance measures are achieved and a payout under the program for that period occurs. The Long-Term Performance Unit Program is structured to reward Named Executive Officers only if performance goals set by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved. TheBeginning with the 2012-2014 performance period, upon vesting, the performance units granted under the Long-Term Performance Unit Program provideswill be settled in shares of Entergy Corporation common stock rather than cash. Accrued dividends on any shares earned during the performance period will also be converted and paid in shares of Entergy Corporation common stock. Entergy Corporation modified the form of payment to align the method of payment with market practice and to encourage the executives to own shares of Entergy Corporation common stock. The Long-Term Performance Unit Program specifies a minimum, target and maximum achievement level. Performance is measuredEntergy Corporation measures performance by assessing Entergy Corporation's total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. The Personnel Committee identified the Philadelphia Utility Index as the industry peer group companies.for total shareholder return performance because the companies included in this index, in the aggregate, approximate Entergy Corporation in terms of business and scale. The Personnel Committee chose relative total shareholder return as a measure of performance because it assesses Entergy Corporation's creation of shareholder value relative to other electric utilities over the performance cycle.period. It also takes into account dividends paid by the companies in this index and normalizes certain events that affect the industry as a whole. Minimum, target, and maximum performance levels are determined by reference to the quartilepercentile ranking of Entergy Corporation's total shareholder return against the total shareholder return of industry peer group companies.
For the 2010-2012 performance cycle, the Personnel Committee identified the Philadelphia Utility Index as the industry peer group for total shareholder return performance because the companies represented in this index more closely approximate Entergy Corporation in terms of size. The companies included in the Philadelphia Utility Index are provided aboveIndex. At any given time, a participant in the Compensation DiscussionLong-Term Performance Unit Program may be participating in up to three performance periods. Currently, participants are participating in the 2011-2013, the 2012-2014, and Analysis under "The Starting Point - Proxy Analysis."the 2013-2015 performance periods.
2012-2014 Performance Unit Program Grants. Subject to achievement of the Performance Unit Program performance levels, the Personnel Committee established target amounts of 22,300 performance units for Mr. Leonard; and 5,300 performance units for each of Mr. Denault and Mr. Smith for the 2010-2012 performance cycle. Thefollowing target amounts for the other Named Executive Officers are as follows: 2,2002012-2014 performance units for Ms. Conley and Mr. Bunting; and 1,000 performance units for each of Mr. Domino, Mr. McDonald, Mr. West, and Mr. Fisackerly. period were:
| · | 26,900 performance units for Mr. Leonard; |
| · | 5,400 performance units for Mr. Denault and Mr. West; |
| · | 4,983 performance units for Mr. Bunting; |
| · | 1,500 performance units for Mr. Domino, Mr. Fisackerly, and Mr. McDonald; |
| · | 2,400 performance units for Mr. Mohl; |
| · | 2,067 performance units for Ms. Mount; |
| · | 1,292 performance units for Ms. Rainer; and |
| · | 1,500 performance units for Mr. Rice. |
The range of payouts under the program is shown below. | Quartiles: | 4 | 3 | 2 | 1 | | Performance Levels: | Zero | Minimum | Target | Maximum | | Total Shareholder Return Ranges: | Below 25th percentile | 25th to 50th percentiles | 50th to 75th percentiles | 75th percentile and above | | Payouts: | No Payout | Interpolate between Minimum and Target (10% to 100% of Target) | Interpolate between Target and Maximum (100% to 250% of Target) | Maximum Payout (250% of Target) |
| Performance Level | Minimum | Target | Maximum | | Total Shareholder Return | 25th percentile | 50th percentile | 75th percentile | | Payouts | 25% of target | 100% of target | 200% of Target |
There is no payout for performance below the 25th percentile. Payouts between minimum and target and target and maximum are calculated using straight-line interpolation. The Personnel Committee sets payout opportunities for the Long-Term Performance Unit Program at the outset of each performance cycle. In determining payout opportunities,period.
Payout for the Committee considers several factors, including:2010-2012 Performance Period. For the 2010-2012 performance period, the target amounts established in January 2010 were:
| · | The advice of the Committee's independent compensation consultant regarding compensation practices at the industry peer group companies; |
· | Competitiveness of the Entergy Corporation's compensation plans and their ability to attract and retain top executive talent; |
· | Target long-term compensation values in the market for similar jobs; |
· | The desire to ensure, as described above, that a substantial portion of total compensation is performance-based; |
· | The relative importance, in any given year, of the long-term performance goals established pursuant to the Performance Unit Program; and |
· | The Committee's assessment of other elements of compensation provided to the Named Executive Officer. |
| For the 2007-2009 performance cycle, the target amounts established in January 2007 were: |
· | 23,800 22,300 performance units for Mr. Leonard; |
| · | 4,500 5,300 performance units for Mr. Denault and Mr. Smith;Denault; |
| · | 2,100 4,583 performance units for Ms. ConleyMr. West; |
| · | 2,803 performance units for Mr. Bunting; |
| · | 1,000 performance units for Mr. Domino, Mr. Fisackerly, and Mr. Bunting;McDonald; |
| · | 2,000 performance units for Mr. Mohl; and |
| · | 1,000 833 performance units for each of Mr. Domino, Mr. McDonald and Mr. Fisackerly.Rice. |
Ms. Mount and Ms. Rainer were not participants in the 2010-2012 performance period of the Long-Term Performance Unit Program. Participants could earn performance units consistent with the range of payouts as described above for the 2010-2012 performance cycle. The Committee established a higher target amount for Mr. Leonard compared to the other Named Executive Officers based on relative total shareholder return and on the following factors:range of payouts:
· Performance Level | Mr. Leonard's leadership and contributions to Entergy Corporation's success as measured by, among other things, the overall performanceMinimum | Target | Maximum | | Total Shareholder Return | 25th percentile | 50th percentile | 75th percentile | | Payouts | 10% of Entergy Corporation. |
· target | Market practices that compensate chief executive officers at greater potential compensation levels with more "pay at risk" than other named executive officers.100% of target | 250% of Target |
In January 2010,2013, the Committee assessed Entergy Corporation's total shareholder return for the 2007-20092010-2012 performance period and determinedin order to determine the actual number of performance units to be paid to Performance Unit Program participants for the 2007-20092010-2012 performance cycle. Performance was measured in a manner similar to that described above for the 2010-2012 cycle, on the basis of relative total shareholder return.
For purposes of determining Entergy Corporation's relative performance for the 2007-2009 performance cycle period, the Committee used the Philadelphia Utility Index as the peer group. Based on market data and the recommendation of management, theperiod. The Committee compared Entergy Corporation's total shareholder return against the total shareholder return of the companies that comprisedcomprise the Philadelphia Utility Index.
Based on athis comparison, of Entergy Corporation's performance relative to the Philadelphia Utility Index as described above, the Committee concluded that Entergy Corporation’s performance for the 2007-20092010-2012 performance cycle,period, ranked in the thirdbottom quartile. This resulted in a payment of 57% of target. Eachzero payout under the Performance Unit Program for the 2010-2012 performance unit was then automatically converted into cash at the rate of $81.84 per unit, the closing price of period.
Stock Options and Restricted Stock
Entergy Corporation commongrants stock on the last trading dayoptions and restricted stock as part of the performance cycle (December 31, 2009), plus dividend equivalents accrued overlong-term incentive awards to the three-year performance cycle. See the 2009 Option Exercises and Stock Vested table for the amount paid to each of the Named Executive Officers for the 2007-2009 performance cycle.executive officers. These awards are intended to:
| · | Stock OptionsAlign the interests of executive officers with the interests of shareholders by tying executive officers’ long-term financial interests to the long-term financial interests of shareholders; |
| · | Act as a retention mechanism for key executives officers; and |
| · | Maintain a market competitive position for total compensation. |
The Personnel Committee and, in the case of the Named Executive Officers (other than Mr. Leonard, Mr. Denault and Mr. Smith), Entergy’s Chief Executive Officer and the Named Executive Officer’s supervisor considerAs previously discussed, several factors are considered in determining the amount of stock options it will grant under Entergy’s 2007 Equity Ownership Planand shares of restricted stock granted to the Named Executive Officers, including:
· | Individual performance; |
· | Prevailing market practice inOfficers. For restricted stock option grants; |
· | The targeted long-term value created by the use of stock options; |
· | The number of participants eligible for stock options, and the resulting "burn rate" (i.e., the number of stock options authorized divided by the total number of shares outstanding) to assess the potential dilutive effect; and |
· | The Committee's assessment of other elements of compensation provided to the Named Executive Officer |
For stock option awards, to the Named Executive Officers (other than Mr. Leonard), the Committee's assessment of individual performance of each Named Executive Officer in consultation with Entergy Corporation's Chief Executive Officer is the most important factor in determining the number of shares of restricted stock and options awarded. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each officer’s performance, role and responsibilities, strengths, and developmental opportunities. It also considers Entergy Corporation’s significant achievements for the prior year.
The following table sets forth the number of stock options and shares of restricted stock granted to each Named Executive Officer in 2009.2012. The exercise price for each option was $77.53,$71.30, which was the closing fair market valueprice of Entergy Corporation common stock on the date of grant.
Named Executive Officer | Stock Options
| J. Wayne Leonard | 125,000 | Leo P. Denault | 45,000 | Richard J. Smith | 35,000 | E. Renae Conley | 12,500 | Hugh T. McDonald | 4,500 | Haley Fisackerly | 3,800 | Joseph F. Domino | 4,500 | Roderick K. West | 5,000 | Theodore H. Bunting | 12,000 |
| Named Executive Officer | Stock Options | Shares of Restricted Stock | | J. Wayne Leonard | 89,000 | 11,600 | | Leo P. Denault | 30,000 | 4,000 | | Roderick K. West | 30,000 | 4,000 | | Theodore H.Bunting, Jr. | 9,000 | 2,100 | | Joseph F. Domino | 7,300 | 700 | | Haley R. Fisackerly | 4,600 | 1,200 | | Hugh T. McDonald | 4,600 | 1,300 | | William M. Mohl | 7,400 | 1,500 | | Alyson M. Mount | - | 1,500 | | Sallie T. Rainer | - | 1,300 | | Charles L. Rice | 4,600 | 1,050 |
The stock option and restricted stock grants awarded to the Named Executive Officers (other than Mr. Leonard) ranged inwere determined based on the factors described above. The executive officers received a larger number between 3,800 and 45,000 shares. In the case of Mr. Leonard, who received 125,000 stock options the Committee took special notein 2012 as compared to 2011 in response to market data that indicated a higher level of his performance as Entergy Corporation's Chief Executive Officer. Among other things, the Committee noted that the total shareholder return of Entergy Corporation measured over the nine-year period between Mr. Leonard's appointment as CEO of Entergy Corporation in January 1999awards was warranted. Ms. Mount and the January 29, 2009 grant date exceeded all of the industry peer group companies as well as all other U.S. utility companies.
For additional information regardingMs. Rainer were not eligible to receive stock options awardedwhen the options were granted in 2009 to each2012.
Stock Options. Under the 2007 Equity Ownership Plan and Entergy’s predecessor equity plans, all stock options must have an exercise price equal to the closing fair market value of Entergy Corporation common stock on the date of grant. In 2008, Entergy Corporation implemented guidelines that require an executive officer to achieveThe stock options vest over a three-year period and maintainhave a levelten-year term from the date of Entergy Corporationgrant. The equity ownership plans prohibit the repricing of “underwater” stock ownership equal to a multiple of his or her salary. Until an executive officer achieves the multiple ownership position of Entergy Corporation common stock, the executive officer (including a Named Executive Officer) upon exercising any stock option granted on or after January 1, 2003, must retain at least 75% of the after-tax net profit from such stock option exercise in the form of Entergy Corporation common stock.options without shareholder approval.
Entergy Corporation has not adopted a formal policy regarding the granting of options at times when itEntergy Corporation is in possession of material non-public information. However, Entergy Corporationoptions are generally grants optionsgranted to Named Executive Officers only during the month of January in connection with itsthe annual executive compensation decisions. On occasion, itoptions may grant optionsbe granted at other times to newly hired employees or existing employees for retention or other limited purposes.
Restricted Stock. Shares of restricted stock vest over a three-year period, have voting rights, and accrue dividends during the vesting period. Upon vesting, shares of Entergy Corporation common stock will be distributed along with the dividends that have accrued on the vested shares. The grant of restricted stock awards replaced a portion of the stock option awards historically granted to the executive officers. Entergy Corporation believes the use of restricted stock enhances retention, mitigates the burn rate, and assists in building executive ownership of Entergy Corporation common stock.
For additional information regarding stock options and shares of restricted stock awarded in 2012 to each of the Named Executive Officers, see the 2012 Grants of Plan-Based Awards table.
Restricted Stock Units Restricted stock units granted under the 20072011 Equity Ownership Plan represent phantom shares of Entergy Corporation common stock (i.e., non-stock interests that have an economic value equivalent to a share of EntergyEntergy’s Corporation common stock). Entergy CorporationRestricted stock units are occasionally grants restricted unitsgranted for retention purposes, to offset forfeited compensation from a previous employer, or for other limited purposes. If all conditions of the grant are satisfied, restrictions on the restricted stock units lift at the end of the restricted period, and a cash equivalent value of the restricted units is paid.paid to the holder of the award. The settlement price is equal to the number of restricted stock units multiplied by the closing price of Entergy Corporation common stock on the date restrictions lift. Restricted stock units are not entitled to dividends or voting rights. Restricted units are generally time-based awards for which restrictions lift, subject to continued employment, generally over a two- to five-year period.
In December 2009,May 2012, the Committee granted Mr. Leonard, Entergy’sDomino, Entergy Corporation’s Chief ExecutiveIntegration Officer 100,0006,000 restricted units. The Committee granted Mr. Leonard these restrictedstock units in recognition of the importance oforder to continue his continued exemplaryemployment with Entergy Corporation as Mr. Domino had been planning on retiring in 2012. Entergy Corporation requested that Mr. Domino remain employed in order to provide his leadership as Chairman and Chief Executive Officer and to encourage the retention of his leadershipskills in light of the numerous strategic challenges facing the Company, including the challenges associated with the completion of the SpinITC Transaction. The Committee also took into account the competitive market for chief executive officers. In determining the size of the grant, the Committee consulted its independent consultantconsidered the declining value of his non-qualified retirement benefits resulting from the request to confirm that the grant was consistent with market practices. The Committee also noted, based on the advice of its independent consultant, that such grants are a commonly used market technique for retention purposes.stay.
The restricted stock units will vest in two equal installments of 50,000 units eachfull on December 3, 2011 and December 3, 2012.May 31, 2014. On eachthe vesting date, Entergy Corporation will pay to Mr. Leonard,Domino, subject to payment of withholding taxes, a cash amount equal to the closing price of a share of Entergy’sEntergy Corporation’s common stock on that date. Under certain conditions, including a terminationdate multiplied by the number of employment without cause, death or disability,restricted stock units granted. At the discretion of Entergy Corporation’s Chief Executive Officer, Mr. Leonard’sDomino’s restricted stock units may vest onat an earlier date.date if the ITC transaction closes early or Entergy Corporation publicly announces that the ITC Transaction has been terminated.
No other Named Executive OfficersOfficer received a restricted units during 2009.
2009 Significant Achievements
In assessing individual and management performance (with respect to the overall compensation of the Named Executive Officers), the Committee noted the following significant achievements:
· | Achieved the safest year in Entergy’s history; |
· | Achieved the highest generation ever from our entire nuclear fleet; |
· | Reported the highest earnings in our history; |
· | Named to “2010 All-America Executive Team” according to rankings compiled by the prestigious Institutional Investors magazine; our Chief Executive Officer and Chief Financial Officer ranked as the top CEO and CFOs in the power industry; Entergy was also ranked as the top electric utility in the country and among the top nine companies in the nation, making it one of the “Most Honored Companies;” |
stock unit grant in 2012. · | Successfully completed Entergy New Orleans storm cost audits for Hurricanes Katrina, Rita, Gustav and Ike and reached agreement with the Louisiana Public Service Commission staff on recoverable Hurricane Gustav and Ike storm costs; |
· | Issued securitized debt for Entergy Texas 2008 storm costs; |
· | Implemented storm reserve accounting at Entergy Arkansas; |
· | Settled rate actions at Entergy Mississippi (annual formula rate plan), Entergy Texas (rate case) and renewed Entergy Gulf States Louisiana and Entergy Louisiana formula rate plans for three years; |
· | Completed the Board approved and previously announced $1.5 billion and $0.5 billion stock buyback programs; |
· | Named for the eighth consecutive year to the Dow Jones Sustainability World Index, an index that tracks the performance of companies that lead their field in terms of corporate sustainability on a global basis; |
· | Recognized for corporate governance practices where in 2009, we received a 100 percent rating for corporate governance in the RiskMetrics Group’s (formerly Institutional Shareholder Services) utility rankings; and |
· | Received multiple awards and recognition, including 11th EEI Emergency Assistance Recovery Award and Platts Global Energy Awards recognizing Entergy New Orleans gas rebuild project as the Global Infrastructure Project of the Year.
|
Benefits, Perquisites, Agreements, and Post-Termination Plans
· | Pension Plan, Pension Equalization Plan, and System Executive Retirement Plan |
Retirement Plans
The Named Executive Officers participate in an Entergy Corporation-sponsored tax qualified pension plan that covers a broad group of employees. This pension plan is a funded, tax-qualified, noncontributory defined benefit pension plan. Benefits under the pension plan are based upon an employee's years of service with an Entergy system company and the employee's average monthly rate of “Eligible Earnings” (which generally includes the employee’s salary and eligible incentive awards, other than incentive awards paid under the Executive Incentive Plan) for the highest consecutive 60 months during the 120 months preceding termination of employment. Benefits under the tax-qualified plan are payable monthly after separation from an Entergy system company. The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law.
Benefits under the tax-qualified pension plan in which theIn addition, each Named Executive Officer (other than Entergy Corporation’s Chief Executive Officer) participates are calculated as an annuity equal to 1.5% of a participant's Eligible Earnings multiplied by years of service. Years of service underin the pension plan formula cannot exceed 40. Contributions to the pension plan are made entirely by the employer and are paid into a trust fund from which the benefits of participants will be paid.
Entergy Corporation sponsors a Pension Equalization Plan which is available to a select group of management and highly compensated employees, including the Named Executive Officers (other than our Chief Executive Officer). The Pension Equalization Plan is a non-qualified unfunded supplemental retirement plan that provides for the payment to participants from an Entergy System employer's general assets a single lump sum cash distribution upon separation from service generally equal to the actuarial present value of the difference between the amount that would have been payable as an annuity under the tax-qualified pension plan, but for Internal Revenue Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified pension benefits, and the amount actually payable as an annuity under the tax-qualified pension plan. The Pension Equalization Plan also takes into account as “Eligible Earnings” any incentive awards paid under the Executive Incentive Plan.
Entergy Corporation also sponsors a System Executive Retirement Plan, which is available totwo non-qualified supplemental retirement plans sponsored by Entergy Corporation. Under the Company's approximately 60 officers, includingterms of the Named Executive Officers (other than Entergy’s Chief Executive Officer). Participation in thePension Equalization Plan and System Executive Retirement Plan, requires individual approval by the plan administrator. Anan employee participating in both the System Executive Retirement Plan and the Pension Equalization Planplans is eligible to receive only the greater of the two single-sum benefits computed in accordance with the terms of and conditions of each plan.
Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from an Entergy System employer’s general assets a single-sum cash distribution upon separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant's annual rate of base salary and Executive Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified Pension Plan benefit and typically any prior employer pension benefit available to the participant. While the System Executive Retirement Plan has a replacement schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.
Years of Service | Executives at Management Level 1 | Executives at Management Level 3 & above - includes the remaining 4 Named Executive Officers | Executives at Management Level 4 | | 20 years | 55.0% | 50.0% | 45.0% | | 30 years | 65.0% | 60.0% | 55.0% |
Mr. Leonard's retention agreement (as further discussed below) provides that, in lieu of his participation in the Pension Equalization Plan and the System Executive Retirement Plan, upon the termination of his employment (unless such termination is for Cause, as defined in the agreement), he will be entitled to receive a benefit equal to 60% of his Final Average Compensation (as described in the description of the System Executive Retirement Plan above) calculated as a single life annuity and payable as an actuarial equivalent lump sum. This benefit will be reduced by other benefits to which he is entitled from any Entergy Corporation-sponsored pension plan or prior employer pension plans. The terms of Mr. Leonard's Supplemental Retirement Benefit were negotiated at the time of his employment with Entergy Corporation and were designed to, among other things, offset the loss of benefits resulting from Mr. Leonard's resignation from his prior employer. At the time that Entergy Corporation recruited Mr. Leonard, he had accumulated twenty-five years of seniority with his prior employer and had served as an executive officer for that employer for over ten years and in an officer-level capacity for over fifteen years.
The Committee believes that the Pension Plan, Pension Equalization Plan and System Executive Retirement Planthese plans are an important part of the Named Executive Officers'executive compensation program. These plans are importantprograms because they assist in the recruitment of top talent in the competitive market, as these types of supplemental plans are typically found in companies of similar size to Entergy Corporation. These plans serve a critically important role in the retention of the senior executives as benefits from these plans generally increase for each year that these executives remain employed by an Entergy system company.us. The plans thereby encourage the most senior executives to remain employed within the Entergy systemby us and continue their work on behalf of Entergy Corporation'sCorporation’s shareholders.
The Entergy System company employer of Ms. Conley, Mr. Smith and Mr. Denault has agreed to provide service credit to each of them under either the Pension Equalization Plan or the System Executive Retirement Plan. Entergy System company employers typically offer these service credit benefits as one element of the total compensation package offered to new mid-level or senior executives that are recruited from other companies. By offering these executives "credited service," Entergy Corporation is able to compete more effectively to hire these employees by mitigating the potential loss of their pension benefits resulting from accepting employment within the Entergy system.
See the 20092012 Pension Benefits table for additional information regarding the operation of the plans described under this caption.
The Named Executive Officers are eligible to participate in an Entergy Corporation-sponsored Savings Plan that covers a broad group of employees. This is a tax-qualified retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30 percent of a participant's base salary up to certain contribution limits defined by law. In addition, under the Savings Plan, the participant's employer matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, on the first six percent of their Earnings (as defined ineligible earnings under the Savings Plan)plan for that pay period. Entergy Corporation maintains the Savings Plan for its employees, of participating Entergy System companies, including the Named Executive Officers, because it wishes to encourage Entergy Corporation’s employees to save some percentage of their cash compensation for their eventual retirement. The Savings Plan permits employees to make such savings in a manner that is relatively tax efficient. ThisEntergy Corporation believes this type of savings plan is also a critical element in attracting and retaining talent in a competitive market.
· | Executive Deferred Compensation |
The Named Executive Officers are eligible to defer up to 100% of their Annual Incentive Plan awards, and until 2014, 100% of their awards under the followingLong-Term Performance Unit Program into theeither or both Entergy Corporation-sponsored Executive Deferred Compensation Plan:
· | Executive Incentive Plan Bonus |
· | Performance Unit Program Awards |
The Named Executive Officers alsoPlan and the equity plan. In addition, they are eligible to defer up to 100% of the following paymentstheir base salary into the 2007 Equity Ownership Plan:
· | Executive Incentive Plan Bonus |
· | Performance Unit Program Awards |
Amounts deferred under the Executive Deferred Compensation Plan and 2007 Equity Ownership Plan are subject to limitations prescribed by law and the respective plan.
Additionally, Mr. Leonard currently has deferred account balances under a frozen Defined Contribution Restoration Plan. These amounts are deemed invested in the options available under this Defined Contribution Plan. The Defined Contribution Plan, until it was frozen in 2005, credited eligible employees deferral accounts with employer contributions to the extent contributions were limited under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.
All deferral amounts represent an unfunded liability of the employer. Amounts deferred into the 2007 Equity Ownership Plan are deemed invested in phantom shares of Entergy Corporation common stock. Amounts deferred under the Executive Deferred Compensation Plan are deemed invested in one or more of the investment options (generally mutual funds) offered under the Savings Plan. Within the Executive Deferred Compensation Plan, the Named Executive Officer may move funds from one deemed investment option to another.
The employer does not "match" amounts that are deferred by employees pursuant to the Executive Deferred Compensation Plan or 2007 Equity Ownership Plan. With the exception of allowing for the deferral of federal and state taxes, Entergy Corporation provides no additional benefit to the Named Executive Officer for deferring any of the above payments. Any increase in value of the deferred amounts results solely from the increase in value of the investment options selected (phantom Entergy Corporation common stock or mutual funds available under the Savings Plan). Deferred amounts are credited with earnings or losses based on the rate of return of deemed investment options or Entergy Corporation common stock, as selected by the participants.
Entergy Corporation provides this benefitthese benefits because the Committee believes it is standard market practice to permit officers to defer the cash portion of their compensation. The Executive Deferred Compensation Plan and 2007 Equity Ownership Plan permit them to do this while also receiving gains or losses on deemed investments, as described above. Entergy
Corporation believes that providing this benefit is important as a retention and recruitment tool as many, if not all, of the companies with which Entergy Corporation and the Subsidiaries competecompetes for executive talent provide a similar arrangement to their senior employees.executive officers. See the 2012 Non-qualified Deferred Compensation table for additional information regarding the operation of the Executive Deferred Compensation Plan. · | Health &Health and Welfare Benefits |
The Named Executive Officers are eligible to participate in various health and welfare benefits available to a broad group of employees. These benefits include medical, dental, and vision coverage, life and accidental death &and dismemberment insurance, and long-term disability insurance. Eligibility, coverage levels, potential employee contributions, and other plan design features are the same for the Named Executive Officers as for the broad employee population.
· | Executive Long-TermExecutive Long-Term Disability Program
|
All of the executive officers, including the Named Executive Officers, are eligible to participate in the Entergy Corporation-sponsored Executive Long-Term Disability program. Individuals who elect to participate in this plan and become disabled under the terms of the plan are eligible for 65 percent of the difference between their base salary and $275,000 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the Entergy Corporation's general long-term disability plan).
Entergy Corporation provides theThe Named Executive Officers are provided with certaina limited number of perquisites and other personal benefits as part of providing a competitive executive compensation program and for employee retention. However,The Personnel Committee reviews all perquisites, are not a material partincluding the use of the compensation program for the Named Executive Officers.corporate aircraft, on an annual basis. In 2009, Entergy Corporation offered to2012 the Named Executive Officers limited benefits such as the following:were offered: corporate aircraft usage, relocation and housing benefits, and annual physical exams. In 2011, Entergy Corporation discontinued providing personal financial counseling for its executive officers and for members of the Office of the Chief Executive, club dues and annual physical exams (whichtax gross up payments on any perquisites (except for relocation benefits) were discontinued. The Named Executive Officers did not receive any additional compensation for the lost value of these discontinued perquisites. Certain of the Named Executive Officers that are mandatory for Entergy’s named executive officers).not members of the Office of the Chief Executive were provided in 2012 with club dues and tax gross up payments on some perquisites. For security and business convenience reasons, Entergy Corporation permits itsthe Chief Executive Officer to use itsthe corporate aircraft at Entergy CorporationCorporation’s expense for personal use. The other Named Executive Officers may use corporate aircraft for personal travel subject to the approval of Entergy Corporation'sCorporation’s Chief Executive Officer. The Personnel Committee reviews all perquisites,From time to time, tickets are made available to cultural and sporting events available to employees, including the use of corporate aircraft, on an annual basis.Named Executive Officers, for business purposes. If not utilized for business purposes, the tickets are made available to employees, including the Named Executive Officers, for personal use. For additional information regarding perquisites, see the "All Other Compensation" column in the 2012 Summary Compensation table.Table.
· | Retention Agreements and other Compensation Arrangements |
The Committee believes that retention and transitional compensation arrangements are an important part of overall compensation. The Committee believes that these arrangements help to secure the continued employment and dedication of the Named Executive Officers, notwithstanding any concern that they might have at the time of a change in control regarding their own continued employment. In addition, the Committee believes that these arrangements are important as recruitment and retention devices, as all or nearly all of the companies with which Entergy Corporation and the Subsidiaries competecompetes for executive talent have similar arrangements in place for their senior employees.
To achieve these objectives, Entergy Corporation has established a System Executive Continuity Plan under which each of the Named Executive Officers (other than Entergy Corporation’s Chief Executive Officer and Chief Financial Officer) is entitled to receive "change in control" payments and benefits if such officer's employment is involuntarily terminated in connection with a change in control. Severance payments under the System Executive Continuity Plan are based on a multiple of the sum of an executive officer’s annual base salary plus his or her average Annual Incentive Plan award at target for similar qualifying eventsthe two fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Under no circumstances can this multiple exceed 2.99 times the sum of (a) annual base salary plus (b) the higher of: (i) the annual incentive award actually awarded to the executive office under the Annual Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs or circumstances. Based on(ii) the market data provided by its independent compensation consultant,average Annual Incentive Plan award for the Committee believestwo fiscal years immediately preceding the fiscal year in which the termination of employment occurs. Entergy Corporation strives to ensure that the benefits and payment levels under the System Executive Continuity Plan are consistent with market practices. The executive officers will not receive any tax gross up payments on any severance benefits received under this plan. In certain cases, the Committee may approve the execution of a retention agreement with an individual executive officer. These decisions are made on a case by case basis to reflect specific retention needs or other factors, including market practice. If a retention agreement is entered into with an individual officer, the Committee considers the economic value associated with that agreement in making overall compensation decisions for the affectedthat officer. Entergy Corporation has voluntarily adopted a policy that any severance arrangements providing benefits in excess of 2.99 times an officer'sofficer’s annual base salary and bonusannual incentive award must be approved by itsEntergy Corporation’s shareholders. Severance payments under the System Executive Retirement Plan are based on the sum of an executive officer’s base salary plus awards granted under the Executive Incentive Plan. Revenue Ruling 2008-13 provides that compensation will not be treated as performance-based under Section 162(m) if it is payable regardless of actual performance in the event of termination by a company without “cause,” by the executive with “good reason” or an executive’s retirement. Effective January 1, 2010, Entergy amended the System Executive Continuity Plan to allow incentive payments under the Executive Incentive Plan to continue to be considered performance-based under Section 162(m). With this amendment, severance payments will be calculated based on the sum of (a) base salary plus (b) the higher of: (i) the annual incentive award actually awarded to the executive office under the Executive Incentive Plan for the fiscal year immediately preceding the fiscal year in which the termination of employment occurs or (ii) the average Executive Incentive Plan award for the two fiscal years immediately preceding the fiscal year in which the termination of employment occurs.
At present,During 2012, Entergy Corporation has entered into ahad retention agreements with Mr. Denault and Mr. Leonard. In general, Mr. Denault’s retention agreement with two of the Named Executive Officers, Mr. Leonard and Mr. Denault. In general, these retention agreements provideprovides for "change in control" payments and other benefits in lieu of to those provided under the System Executive Continuity Plan. The retention agreements entered intoAs with Mr. Leonard andany severance benefits paid under the System Executive Continuity Plan, Mr. Denault will not receive tax gross up payments on any severance benefits he may receive under his agreement. Mr. Denault’s retention agreement was designed to reflect among other things, the competition for chief executive officer and chief financial officer talent in the market placemarketplace and the Committee'sCommittee’s assessment of the critical role of these officersthis position plays in executing Entergy Corporation'sCorporation’s long-term financial and other strategic objectives. Effective January 1, 2010, Entergy made amendments similar to those made to the System Executive Continuity Plan to Mr. Denault’s and Mr. Leonard’s retention agreements to allow incentive payments under the Executive Incentive Plan to continue to be considered performance based under Section 162(m). Based on the market data provided by its former independent compensation consultant, the Personnel Committee believes the benefits and payment levels under theseMr. Denault’s retention agreementsagreement are consistent with market practices.
On December 18, 2009, Entergy entered into aPursuant to his retention agreement, with Richard J. Smith, its President and Chief Operating Officer. This agreement provides forupon retirement, Mr. Smith’s continued employment and the payment of certain compensation to Mr. Smith in the event the planned Spin Transaction does not occur. The agreement provides that in such event, Mr. Smith will continue to be employed by an Entergy System Company at a management level and with a salary no less than Mr. Smith’s current management level and salary and that his duties will include, among other things, coordinating the orderly unwinding of the preparations for the contemplated Spin Transaction. In addition, the agreement provides that Mr. Smith will be entitledLeonard was eligible to receive a lump sum cash payment equal to 1.5 times60% of his base salary as“final average compensation” (as described in the description of the date of separationSystem Executive Retirement Plan) reduced by other benefits to which he was entitled from Entergy ifCorporation-sponsored pension plan and prior employer pension plans. Mr. Leonard was not a participant in either (i)the Pension Equalization or System Executive Retirement Plans and received the supplemental retirement payment in lieu of benefits from these plans. The terms of Mr. Leonard’s supplemental retirement benefit contained in his retention agreement were negotiated at the time his employment with Entergy Corporation commenced and were designed to, among other things, offset the loss of benefits resulting from Mr. Leonard’s resignation from his prior employer. At the time that Entergy Corporation recruited Mr. Leonard, he remains continuously employedhad accumulated twenty-five years of seniority with his prior employer and had served as an executive officer for that employer for over ten years and in suchan officer-level capacity for 24 months after any public announcement that the Spin Transaction will not occur or (ii) he remains continuously employed in such capacity for at least six (6) months after any such public announcement and thereafter retires with the consent of Entergy’s Chief Executive Officer prior to reaching such 24 months of service. Entergy entered into this agreement with Mr. Smith in light of Mr. Smith’s leadership role in the preparations for the Spin Transaction and the critical role that Mr. Smith would have in dismantling these preparations should the Spin Transaction not occur. In determining the type and size of the amount of payment under this agreement, the Personnel Committee consulted with its independent compensation consultant to confirm that the economic value of this arrangement was consistent with market practices.over fifteen years.
For additional information regarding the System Executive Continuity Plan and Mr. Leonard’s and Mr. Denault’s retention agreementagreements described above, see "Potential“2012 Potential Payments upon Termination or Change in Control."”
Compensation Program Administration
Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in its industry as well as Fortune 500 companies. Some of these practices include the following:
Clawback Provisions
Entergy Corporation has adopted the Entergy Corporation Policy Regarding Recoupment of Certain Compensation. This policy covers individuals subject to Section 16 of the Exchange Act. Under the policy, the Committee will require reimbursement of incentives paid to these executive officers where:
| · | (i) the payment was predicated upon the achievement of certain financial results with respect to the applicable performance period that were subsequently the subject of a material restatement other than a restatement due to changes in accounting policy; or (ii) a material miscalculation of a performance award occurs whether or not the financial statements were restated and, in either such case, a lower payment would have been made to the executive officer based upon the restated financial results or correct calculation; or |
| · | in the Board of Directors’ view, the executive officer engaged in fraud that caused or partially caused the need for a restatement or caused a material miscalculation of a performance award whether or not the financial statements were restated. |
The amount the Committee requires to be reimbursed is equal to the excess of the gross incentive payment made over the gross payment that would have been made if the original payment had been determined based on the restated financial results or correct calculation. Further, following a material restatement of its financial statements, Entergy Corporation will seek to recover any compensation received by Entergy Corporation’s Chief Executive Officer and Chief Financial Officer that is required to be reimbursed under Section 304 of the Sarbanes-Oxley Act of 2002.
Stock Ownership Guidelines
For many years, Entergy Corporation has had stock ownership guidelines for executives, including the Named Executive Officers. These guidelines are designed to align the executives’ long-term financial interests with those of Entergy Corporation’s shareowners. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines. The ownership guidelines are as follows: | Role | Value of Common Stock to be Owned | | Chief Executive Officer | 5 times base salary | | Executive Vice Presidents | 4 times base salary | | Senior Vice Presidents | 2.5 times base salary | | Vice Presidents | 1.5 times base salary |
Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines: (i) upon exercising any stock option, he or she must retain at least 75% of the after-tax net profit from such stock option exercise in the form of Entergy common stock, (ii) he or she must retain all net after-tax shares of Entergy Corporation’s restricted stock received upon vesting, and (iii) he or she must retain all net after-tax shares paid out under the Long-Term Performance Unit Program, which will payout 100% in Entergy Corporation stock commencing with the 2012-2014 performance period. Trading Controls and Anti-Pledging and Anti-Hedging Policies
Executive officers, including the Named Executive Officers, are required to receive the permission of Entergy Corporation’s General Counsel prior to entering into any transaction involving company securities, including gifts, other than the exercise of employee stock options. Trading is generally permitted only during open trading windows occurring immediately following the release of earnings. Employees, who are subject to trading restrictions, including the Named Executive Officers, may enter into trading plans under Rule 10b5-1 of the Exchange Act, but these trading plans may be entered into only during an open trading window and must be approved by Entergy Corporation. The Named Executive Officer bears full responsibility if he or she violates corporate policy by permitting shares to be bought or sold without pre-approval or when trading is restricted.
Entergy Corporation also prohibits its directors and executive officers, including the Named Executive Officers, from pledging any Entergy Corporation securities or entering into margin accounts involving Entergy Corporation securities. These transactions are prohibited because of the potential that sales of Entergy Corporation securities could occur outside trading periods and without the required approval of the General Counsel.
Entergy Corporation also has adopted an anti-hedging policy that prohibits officers, directors, and employees from entering into hedging or monetization transactions involving Entergy Corporation’s common stock. Prohibited transactions include, without limitation, zero-cost collars, forward sale contracts, purchase or sale of options, puts, calls, straddles or equity swaps or other derivatives that are directly linked to Entergy Corporation’s stock or transactions involving “short-sales” of Entergy Corporation’s stock. The Board adopted this policy to require officers, directors, and employees to continue to own Entergy stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’s other shareholders Compensation Consultant Independence Policy
To ensure the independence of the Personnel Committee’s compensation consultant, the Board has adopted a policy that any consultant (including its affiliates) retained by the Board of Directors or any Committee of the Board of Directors to provide advice or recommendations on the amount or form of executive and director compensation should not be retained by Entergy Corporation or any of its affiliates to provide other services in an aggregate amount that exceeds $120,000 in any year. In 2012 the Personnel Committee’s independent compensation consultant, Pay Governance LLC, did not provide any services to Entergy Corporation other than its services to the Personnel Committee. Annually, the Committee reviews the relationship with its compensation consultant including services provided, quality of those services, and fees associated with services during the fiscal year to ensure the executive compensation consultant’s independence is maintained.
Roles and Responsibilities
Role of Personnel Committee
The Personnel Committee has overall responsibility for approving the compensation program for the Named Executive Officers and makes all final compensation decisions regarding the Named Executive Officers. The Committee works with executive management to ensure that the compensation policies and practices are consistent with Entergy Corporation's namedCorporation’s values and support the successful recruitment, development and retention of executive officers.talent so Entergy Corporation can achieve its business objectives and optimize long-term financial returns. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with its philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to Entergy Corporation's named executive officers:the Named Executive Officers: | · | developing and implementing compensation policies and programs for the executive officers, including any employment agreement with an executive officer; |
| · | evaluating the performance of Entergy Corporation'sCorporation’s Chairman and Chief Executive Officer; and |
| · | reporting, at least annually, to the Board on succession planning, including succession planning for Entergy Corporation'sthe Chief Executive Officer. |
The Personnel Committee has authorized, in limited circumstances, the delegation of its authority to grant stock options under Entergy plans to Entergy Corporation's Chairman and Chief Executive Officer and Senior Vice President of Human Resources and Administration subject to the following conditions:
· | No grant may exceed an aggregate value of $1 million per grantee; |
· | All awards must be issued in accordance with the terms of Entergy Corporation's plans, including the requirement that all options be issued for an exercise price not less than the fair market value of the stock on date the option is granted; |
· | No awards may be granted to any employee of Entergy Corporation subject to Section 16 of the Securities Exchange Act of 1934; and |
· | The Personnel Committee must be advised on at least a quarterly basis of the grants made under the exercise of this delegated authority. |
Certain aspects of the compensation of officers who are not Entergy named executive officers, Mr. Bunting, Ms. Conley, Mr. Domino, Mr. Fisackerly and Mr. McDonald are not directly determined by the Personnel Committee. While the Committee does determine the number of performance units to be granted to these Named Executive Officers, the Committee does not determine the actual annual incentive target for these Named Executive Officers. Rather, the Committee establishes an overall available annual incentive pool for these officers and establishes the specific goal targets and ranges, the officers’ respective supervisor determines the actual incentive payment, in each case, subject to the ultimate approval of Entergy’s Chief Executive Officer. Further, Entergy’s Chief Executive Officer and the officer’s supervisor have ultimate responsibility for adjusting the salary of these Named Executive Officers as deemed appropriate. The officer’s supervisor and Entergy’s Chief Executive Officer also determine how many stock option awards are to be allocated to the Named Executive Officers from an available pool established by the Personnel Committee for similarly situated officers, though the Personnel Committee ultimately approves the options granted.
Role of Chief Executive Officer
The Personnel Committee solicits recommendations from Mr. Leonard, Entergy Corporation'sCorporation’s Chief Executive Officer with respect to compensation decisions for Mr. Denault and Mr. Smith. Mr. Leonard's role is limited to:individual Named Executive Officers (other than himself).
| · | providingSpecifically, Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of Mr. Denaulteach Named Executive Officer and Mr. Smith;recommends compensation levels to be awarded to each Named Executive Officer other than himself. In addition, the Committee may request that the Chief Executive Officer provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in the structure of bonus programs. The Personnel Committee also relies on the recommendations of the senior human resources executives with respect to compensation decisions, policies, and practices. Entergy Corporation’s Chief Executive Officer does not play any role with respect to any matter affecting his own compensation, nor does he have any role determining or recommending the amount, or form of, director compensation. |
· | recommending base salary, annual merit increases, stock option and annual cash incentive plan compensation amounts for these officers. |
In addition, the CommitteeThe Chief Executive Officer may request that Mr. Leonard provide management feedback and recommendations on changes in the design of compensation programs, such as special retention plans or changes in structure of bonus programs. Mr. Leonard does not play any role with respect to any matter affecting his own compensation nor does he have any role determining or recommending the amount, or form, of director compensation.
As noted above, under “Role of Personnel Committee,” Mr. Leonard also plays a role in determining the Subsidiary Named Executive Officers’ base salary, their annual incentive target and the number of stock options they receive.
Mr. Leonard may attend committee meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. However, he is not in attendance at the portion of any meeting when the Committee determines and approves the compensation to be paid to the Named Executive Officers. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2009,2012, Mr. Leonard attended five3 meetings of the Personnel Committee.
In 2009, the Committee's compensation consultant met at the request of the Personnel Committee with Mr. Leonard to review market trends in executive and management compensation and to discuss Entergy Corporation and its Subsidiaries’ overall compensation philosophy, such as the optimum balance between base and incentive compensation. In addition, the Committee requested that its independent compensation consultant interview Mr. Leonard to obtain management feedback on the impact of compensation programs on employees and information regarding the roles and responsibilities of the Named Executive Officers.
Role of the Compensation Consultant
The Personnel Committee has the sole authority from the Board of Directors for the appointment, compensation, and oversight of its outside compensation consultant. In discharging its duties,2012 the Personnel Committee has retained Towers Watson, formerly Towers Perrin,Pay Governance LLC as its independent compensation consultant to assist it in, among other things, evaluating different compensation programs and developing market data to assess the compensation programs. Under
During 2012, Pay Governance assisted the termsCommittee with its responsibilities related Entergy Corporation’s compensation programs for its executives. Specifically, the Committee directed Pay Governance to: (i) regularly attend meetings of its engagement, Towers Watson reports directlythe Committee; (ii) conduct studies of competitive compensation practices; (iii) identify Entergy Corporation’s market surveys and proxy peer group; (iv) review base salary, annual incentives, and long-term incentive compensation opportunities relative to competitive practices; and (v) develop conclusions and recommendations related to the executive compensation plan of Entergy Corporation for consideration by the Committee. A senior consultant from Pay Governance attended all Personnel Committee meetings to which has the right to retain or dismiss the consultant without the consent of Entergy Corporation's management. In addition, the consent of the Personnel Committee must be obtained before Towers Watson can accepthe was invited in 2012. Pay Governance did not provide any material engagements from Entergy Corporation’s management.
In considering the appointment of Towers Watson, the Personnel Committee took into account that Towers Watson provides from time to time general consultingother services to Entergy Corporation's management with respect to non-executive compensation matters. In this connection the Committee reviewed the fees and compensation received by Towers Watson for these services over a historical period. After considering the nature and scope of these engagements and the fee arrangements involved, the Personnel Committee determined that the engagements did not create a conflict of interest. The Committee reviews on an ongoing basis the fees and compensation received by Towers Watson for non-executive compensation matters on an annual basis to monitor its independence. In 2009, Entergy incurredCorporation in the aggregate fees of $234,668 from Towers Watson for determining or recommending the amount or form of executive and director compensation and $1,363,128 for other services, $1,141,054 of which was for services related to the Spin Transaction.2012.
Tax and Accounting Considerations
Section 162(m) of the Internal Revenue Code limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to athe Chief Executive Officer or any of its other Named Executive Officers (other than the chief financial officer)Chief Financial Officer), unless that compensation is "performance-based compensation" within the meaning of Section 162(m). The Personnel Committee considers deductibility under Section 162(m) as it structures the compensation packages that are provided to Entergy’sits Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to the Named Executive Officers. However, the Personnel Committee and the Board believe that it is in the best interest of Entergy Corporation that the Personnel Committee retains the flexibility and discretion to make compensation awards, whether or not deductible. This flexibility is necessary to foster achievement of performance goals established by the Personnel Committee, as well as, other corporate goals that the Committee deems important to Entergy Corporation and the Subsidiaries'Corporation's success, such as encouraging employee retention and rewarding achievement.achievement of key corporate goals.
Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to Entergy’s Named Executive Officers. However, the Personnel Committee and the Entergy Board of Directors believe that it is in the best interest of Entergy that the Personnel Committee retains the flexibility and discretion to make compensation awards regardless of their financial accounting consequences.
PERSONNEL COMMITTEE REPORT
The "Personnel Committee Report" included in the Entergy Corporation Proxy Statement is incorporated by reference, but will not be deemed to be "filed" in this Annual Report on Form 10-K. None of the Subsidiaries has a compensation committee, or other board committee performing equivalent functions. The board of directors of each of the Subsidiaries is comprised of individuals who are officers or employees of Entergy Corporation or one of the Subsidiaries. These boards do not make determinations regarding the compensation paid to executive officers of the Subsidiaries.
EXECUTIVE COMPENSATION TABLES
20092012 Summary Compensation Table
The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal years ended December 31, 2009, 20082012, 2011, and 2007.2010. For information on the principal positions held by each of the Named Executive Officers, see Item 10, "Directors“Directors and Executive Officers of the Registrants."” The compensation set forth in the table represents the aggregate compensation paid by all Entergy System companies. None of the Entergy System companies has entered into any employment agreements with any of the Named Executive Officers (other than the retention agreements described in "Potential“Potential Payments upon Termination or Change in Control"Control”). For additional information regarding the material terms of the awards reported in the following tables, including a general description of the formula or criteria to be applied in determining the amounts payable, see "Compensation“Compensation Discussion and Analysis."”
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | Name and Principal Position | | Year | | Salary (1) | | Bonus (2) | | Stock Awards (3) | | Option Awards (4) | | Non-Equity Incentive Plan Compensation (5) | | Change in Pension Value and Nonqualified Deferred Compensation Earnings (6) | | All Other Compensation (7) | | Total | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compensation (6) | | Change in Pension Value and Non-qualified Deferred Compensation Earnings (7) | | All Other Compensation (8) | | Total | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Theodore H. Bunting, Jr. | | 2009 | | $361,388 | | $ - | | $155,060 | | $143,280 | | $335,000 | | $535,700 | | $23,065 | | $1,553,493 | | 2012 | | $473,286 | | $ - | | $585,787 | | $84,780 | | $372,400 | | $623,800 | | $23,817 | | $2,163,870 | | Acting principal financial | | 2008 | | $336,948 | | $ - | | $151,480 | | $289,350 | | $400,023 | | $225,000 | | $61,294 | | $1,464,095 | | | Former principal financial | | | 2011 | | $356,884 | | $ - | | $351,108 | | $78,064 | | $400,000 | | $632,100 | | $14,094 | | $1,832,250 | | officer – Entergy Arkansas, | | | | | | | | | | | | | | | | | | | | 2010 | | $350,448 | | $ - | | $237,864 | | $194,155 | | $525,000 | | $392,300 | | $22,609 | | $1,722,376 | | Entergy Gulf States Louisiana, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Entergy Louisiana, Entergy | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Mississippi, Entergy New | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Orleans, Entergy Texas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | E. Renae Conley | | 2009 | | $423,360 | | $15,000 | | $155,060 | | $149,250 | | $307,000 | | $406,000 | | $42,899 | | $1,498,569 | | | CEO-Entergy Louisiana and | | 2008 | | $403,096 | | $ - | | $151,480 | | $250,770 | | $415,000 | | $107,700 | | $90,525 | | $1,418,571 | | | CEO-Entergy Gulf States | | 2007 | | $388,250 | | $ - | | $192,822 | | $314,500 | | $320,000 | | $276,700 | | $79,392 | | $1,571,664 | | | Louisiana | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Leo P. Denault | | 2009 | | $654,231 | | $ - | | $372,144 | | $537,300 | | $507,150 | | $837,200 | | $60,688 | | $2,968,713 | | 2012 | | $669,564 | | $ - | | $647,594 | | $282,600 | | $448,779 | | $972,400 | | $22,657 | | $3,043,594 | | Executive Vice President and | | 2008 | | $621,231 | | $ - | | $2,973,900 | | $803,750 | | $617,400 | | $250,500 | | $150,285 | | $5,417,066 | | 2011 | | $648,512 | | $ - | | $891,941 | | $287,000 | | $587,059 | | $980,400 | | $16,756 | | $3,411,668 | | CFO – Entergy Corp. | | 2007 | | $584,422 | | $ - | | $413,190 | | $943,500 | | $516,600 | | $535,000 | | $128,933 | | $3,121,645 | | 2010 | | $630,000 | | $ - | | $573,036 | | $669,500 | | $758,520 | | $528,600 | | $52,276 | | $3,211,932 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Joseph F. Domino | | 2009 | | $329,976 | | $10,000 | | $69,777 | | $53,730 | | $111,373 | | $322,100 | | $45,396 | | $942,352 | | 2012 | | $328,814 | | $ - | | $537,755 | | $68,766 | | $165,000 | | $305,700 | | $19,443 | | $1,425,478 | | CEO - Entergy Texas | | 2008 | | $314,610 | | $ - | | $75,740 | | $112,525 | | $230,000 | | $92,800 | | $62,873 | | $888,548 | | | Former CEO - Entergy Texas | | | 2011 | | $322,418 | | $ - | | $172,899 | | $33,292 | | $215,000 | | $573,500 | | $19,207 | | $1,336,316 | | | | 2007 | | $304,122 | | $ - | | $91,820 | | $188,700 | | $135,000 | | $515,900 | | $62,089 | | $1,297,631 | | 2010 | | $317,754 | | $ - | | $108,120 | | $61,594 | | $317,754 | | $224,500 | | $33,476 | | $1,063,198 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Haley R. Fisackerly | | 2009 | | $274,999 | | $8,250 | | $69,777 | | $45,372 | | $138,000 | | $168,300 | | $35,675 | | $740,373 | | 2012 | | $287,296 | | $30,000 | | $186,225 | | $43,332 | | $139,000 | | $284,900 | | $26,781 | | $997,534 | | CEO – Entergy Mississippi | | 2008 | | $248,346 | | $41,000 | | $63,081 | | $64,550 | | $125,700 | | $143,500 | | $14,531 | | $700,708 | | 2011 | | $280,885 | | $ - | | $172,899 | | $33,292 | | $150,000 | | $295,700 | | $16,603 | | $949,379 | | | | | | | | | | | | | | | | | | | | | | 2010 | | $274,999 | | $ - | | $108,120 | | $120,510 | | $192,500 | | $190,000 | | $39,370 | | $925,499 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | | | 2012 | | $1,343,148 | | $ - | | $2,632,339 | | $838,380 | | $1,539,315 | | $5,892,800 | | $95,884 | | $12,341,866 | | Chairman of the Board and | | | 2011 | | $1,315,229 | | $ - | | $3,163,825 | | $803,600 | | $2,033,356 | | $2,749,700 | | $65,061 | | $10,130,771 | | CEO - Entergy Corp. | | | 2010 | | $1,291,500 | | $ - | | $2,411,076 | | $1,807,650 | | $2,665,656 | | $ - | | $104,185 | | $8,280,067 | | | | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | | | 2012 | | $334,891 | | $30,000 | | $193,355 | | $43,332 | | $202,000 | | $452,900 | | $38,819 | | $1,295,297 | | CEO-Entergy Arkansas | | | 2011 | | $327,892 | | $ - | | $172,899 | | $33,292 | | $210,000 | | $485,000 | | $28,320 | | $1,257,403 | | | | | 2010 | | $322,132 | | $ - | | $108,120 | | $61,594 | | $297,972 | | $205,000 | | $54,990 | | $1,049,808 |
| (a) | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | Name and Principal Position | Year | | Salary (1) | | Bonus (2) | | Stock Awards (3) | | Option Awards (4) | | Non-Equity Incentive Plan Compensation (5) | | Change in Pension Value and Nonqualified Deferred Compensation Earnings (6) | | All Other Compensation (7) | | Total | | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | 2009 | | $1,341,174 | | $ - | | $9,850,425 | | $1,492,500 | | $1,782,270 | | $499,800 | | $200,040 | | $15,166,209 | | Chairman of the Board and | 2008 | | $1,273,523 | | $ - | | $1,785,300 | | $2,813,125 | | $2,169,720 | | $313,200 | | $759,739 | | $9,114,607 | | CEO - Entergy Corp. | 2007 | | $1,216,443 | | $ - | | $2,185,316 | | $4,009,875 | | $1,815,480 | | $4,879,200 | | $613,661 | | $14,719,975 | | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | 2009 | | $324,610 | | $10,000 | | $69,777 | | $53,730 | | $128,066 | | $252,500 | | $67,221 | | $905,904 | | CEO-Entergy Arkansas | 2008 | | $319,286 | | $ - | | $75,740 | | $112,525 | | $160,500 | | $42,700 | | $74,830 | | $785,581 | | | 2007 | | $309,088 | | $ - | | $91,820 | | $188,700 | | $120,000 | | $182,800 | | $61,851 | | $954,259 | | | | | | | | | | | | | | | | | | | | | Richard J. Smith | 2009 | | $669,807 | | $ - | | $372,144 | | $417,900 | | $519,225 | | $755,900 | | $140,779 | | $2,875,755 | | President and Chief Operating | 2008 | | $638,394 | | $ - | | $421,980 | | $562,625 | | $632,100 | | $391,400 | | $220,708 | | $2,867,207 | | Officer - Entergy Corp. | 2007 | | $599,612 | | $ - | | $413,190 | | $943,500 | | $535,886 | | $743,700 | | $153,733 | | $3,389,621 | | | | | | | | | | | | | | | | | | | | | Roderick K. West | 2009 | | $327,115 | | $15,000 | | $69,777 | | $59,700 | | $158,000 | | $191,200 | | $40,883 | | $861,675 | | CEO-Entergy New Orleans | 2008 | | $300,474 | | $ - | | $1,755,590 | | $128,600 | | $252,000 | | $164,200 | | $54,465 | | $2,655,329 | | | 2007 | | $270,752 | | $ - | | $91,820 | | $188,700 | | $155,000 | | $16,800 | | $43,543 | | $766,615 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | Name and Principal Position (1) | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compensation (6) | | Change in Pension Value and Non-qualified Deferred Compensation Earnings (7) | | All Other Compensation (8) | | Total | | | | | | | | | | | | | | | | | | | | | | William M. Mohl | | 2012 | | $340,447 | | $30,000 | | $268,014 | | $69,708 | | $300,000 | | $448,600 | | $17,169 | | $1,473,938 | | CEO-Entergy Louisiana and | | 2011 | | $332,751 | | $ - | | $303,794 | | $70,028 | | $265,000 | | $388,900 | | $26,668 | | $1,387,141 | | CEO-Entergy Gulf States | | 2010 | | $299,193 | | $ - | | $216,240 | | $120,510 | | $380,250 | | $166,718 | | $148,767 | | $1,331,678 | | Louisiana | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Alyson M. Mount | | 2012 | | $252,389 | | $ - | | $320,401 | | $ - | | $210,000 | | $384,700 | | $11,556 | | $1,179,046 | | Acting principal financial | | | | | | | | | | | | | | | | | | | | officer – Entergy Arkansas, | | | | | | | | | | | | | | | | | | | | Entergy Gulf States Louisiana, | | | | | | | | | | | | | | | | | | | | Entergy Louisiana, Entergy | | | | | | | | | | | | | | | | | | | | Mississippi, Entergy New | | | | | | | | | | | | | | | | | | | | Orleans, Entergy Texas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Sallie T. Rainer | | 2012 | | $251,907 | | $30,000 | | $215,262 | | $ - | | $128,000 | | $581,300 | | $13,714 | | $1,220,183 | | CEO - Entergy Texas | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Charles L. Rice, Jr. | | 2012 | | $250,781 | | $30,000 | | $175,530 | | $43,332 | | $115,000 | | $96,900 | | $24,422 | | $735,965 | | CEO-Entergy New Orleans | | 2011 | | $245,312 | | $ - | | $154,702 | | $33,292 | | $130,000 | | $78,400 | | $20,594 | | $662,300 | | | | 2010 | | $203,879 | | $9,962 | | $90,064 | | $ - | | $192,000 | | $30,944 | | $18,708 | | $545,557 | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | 2012 | | $584,540 | | $ - | | $647,594 | | $282,600 | | $391,791 | | $991,000 | | $46,097 | | $2,943,622 | | Executive Vice President and | | 2011 | | $566,162 | | $ - | | $746,361 | | $195,160 | | $512,512 | | $664,800 | | $20,261 | | $2,705,256 | | Chief Administrative Officer, | | 2010 | | $441,539 | | $ - | | $495,514 | | $93,730 | | $662,200 | | $207,000 | | $46,915 | | $1,946,898 | | Entergy Corp. | | | | | | | | | | | | | | | | | | |
| (1) | Effective February 1, 2013, Mr. Leonard retired from Entergy. Mr. Denault succeeded Mr. Leonard as Chairman of the Board and Chief Executive Officer of Entergy Corporation. Information presented in the tables reflects the positions and compensation for each of these individuals as of December 31, 2012. | | (2) | The amounts in column (c) represent the actual base salary paid to the Named Executive Officer. ChangesThe 2012 changes in base salarysalaries noted in the Compensation Discussion and Analysis were effective in April of the years shown and the base salary disclosed above is a combination of the two rates in effect during the year. The Named Executive Officers are paid on a bi-weekly basis and there was an extra pay period during calendar year 2009.2012. | (2)(3) | The amounts in column (d) for 2009 reflect the cash bonuses paid to Ms. Conley, Mr. Domino, Mr. Fisackerly, Mr. McDonald, Mr. Mohl, Ms. Rainer, and Mr. West in lieu of an increase in their base salary. In 2008, Mr. Fisackerly receivedRice represent a cash bonus paid in recognition of their work supporting the move to compensate him for his discontinued participation in the Nuclear Retention Plan.MISO. | (3)(4) | The amounts in column (e) represent the aggregate grant date fair value of restricted stock, restricted stock units, and performance units granted under the 2009 – 2011 Performance Unit Program of the Equity Ownership Plan calculated in accordance with accounting standards. For Mr. Leonard, it also includes theFASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock and the restricted stock units granted to him in December 2009 calculated in accordance with accounting standards.is based on the closing price of Entergy Corporation common stock on the date of grant. The amounts included in column (e) for the 2009 – 2011 Plan are calculatedgrant date fair value of performance units is based on the probable satisfactionoutcome of the applicable performance conditions.conditions, measured using a Monte Carlo simulation valuation model. The simulation model applies a risk-free interest rate and an expected volatility assumption. The risk-free rate is assumed to equal the yield on a three-year treasury bond on the grant date. Volatility is based on historical volatility for the 36-month period preceding the grant date. If the highest achievement level of performance is achieved,attained, the maximum amounts that will be received underwith respect to the plan2012 performance units are as follows: Mr. Bunting, $387,650; Ms. Conley, $387,650;$942,109; Mr. Denault, $930,360;$770,040; Mr. Domino, $174,443;$213,900; Mr. Fisackerly, $174,443;$213,900; Mr. Leonard, $4,361,063;$3,835,940; Mr. McDonald, $174,443;$213,900; Mr. Smith, $930,360;Mohl, $342,240; Ms. Mount, $436,997; Ms. Rainer, $248,441; Mr. Rice, $213,900; and Mr. West, $174,443. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the Financial Statements.$770,040. |
(4)(5) | The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 Equity Ownership Plan calculated in accordance with accounting standards.FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the Financial Statements.financial statements. | (5)(6) | The amounts in column (g) represent cash payments made under the ExecutiveAnnual Incentive Plan. | (6)(7) | The amounts in column (h), except for Mr. Leonard, include the annual actuarial increase in the present value of the Named Executive Officer'sOfficers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation'sCorporation’s financial statements and includes amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2009“2012 Pension Benefits”). For Mr. Leonard, who retired in February 2013, the amount was calculated using the rate with which the lump sum will actually be calculated as prescribed by the Internal Revenue Service resulting in a larger increase in pension value. None of the increase is attributable to above-market or preferential earnings on nonqualifiednon-qualified deferred compensation (see “2009 Nonqualified“2012 Non-qualified Deferred Compensation”). For 2010, the aggregate change in the actuarial present value of Mr. Leonard’s pension benefits was a decrease of $539,200. | (7)(8) | The amounts set forth in column (i) for 20092012 include (a) matching contributions by Entergy Corporation to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (c)(d) tax gross up payments relating toon perquisites; (d) dividends paid on stock awards and (e) perquisites and other compensation. The amounts are listed in the following table: |
Named Executive Officer | Company Contribution – Savings Plan | Life Insurance Premium | Tax Gross Up Payments | Dividends Paid on Stock Awards | Perquisites and Other Compensation | Total | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | Perquisites and Other Compensation | Total | | Theodore H. Bunting, Jr. | $9,750 | $3,708 | $768 | $8,839 | $ - | $23,065 | $10,500 | $2,037 | $3,945 | $ - | $7,335 | $23,817 | | Renae E. Conley | $10,054 | $988 | $7,021 | $10,230 | $14,606 | $42,899 | | | Leo P. Denault | $9,750 | $3,944 | $9,212 | $22,015 | $15,767 | $60,688 | $10,500 | $5,821 | $4,041 | $ - | $2,295 | $22,657 | | Joseph F. Domino | $9,750 | $5,900 | $8,886 | $4,910 | $15,950 | $45,396 | $10,500 | $1,048 | $6,122 | $ - | $1,773 | $19,443 | | Haley R. Fisackerly | $7,377 | $270 | $10,138 | $2,455 | $15,435 | $35,675 | $10,500 | $1,048 | $428 | $3,767 | $11,038 | $26,781 | | J. Wayne Leonard | $9,750 | $7,482 | $15,871 | $116,376 | $50,561 | $200,040 | $10,500 | $13,390 | $11,636 | $ - | $60,358 | $95,884 | | Hugh T. McDonald | $8,226 | $3,420 | $22,014 | $4,910 | $28,651 | $67,221 | $10,500 | $1,048 | $3,564 | $7,930 | $15,777 | $38,819 | | Richard J. Smith | $9,750 | $3,070 | $49,656 | $22,015 | $56,288 | $140,779 | | | William M. Mohl | | $10,500 | $1,279 | $2,683 | $ - | $2,707 | $17,169 | | Alyson M. Mount | | $10,500 | $814 | $242 | $ - | $ - | $11,556 | | Sallie T. Rainer | | $10,500 | $580 | $2,634 | $ - | $ - | $13,714 | | Charles L. Rice, Jr. | | $10,500 | $755 | $3,184 | $2,196 | $7,787 | $24,422 | | Roderick K. West | $10,290 | $696 | $11,201 | $4,910 | $13,786 | $40,883 | $10,500 | $3,494 | $1,673 | $ - | $30,430 | $46,097 |
Perquisites and Other Compensation
The amounts set forth in column (i) include perquisites and other personal benefits that Entergy Corporation provides to the Named Executive Officers as part of providing a competitive executive compensation program and for employee retention. In 2012, the Named Executive Officers were offered the following personal benefits: corporate aircraft usage, relocation and housing benefits, annual physical exams, club dues for officers who are not a member of the Office of Chief Executive, and event tickets. Tickets to cultural and sporting events are purchased for business purposes; if not utilized for business purposes, the tickets are made available to the employees, including the Named Executive Officers, for personal use. The following perquisites and other compensation were provided by Entergy Corporation in 2009 to the Named Executive Officers:2012:
Named Executive Officer | Financial Counseling | Club
Dues
| Personal Use of Corporate Aircraft | Club RelocationDues
| Executive Physicals | Event
Tickets | | Theodore H. Bunting, Jr. | | | | | | E. Renae Conley | x | | x | | x | | Leo P. Denault | x | | | x | x | | Joseph F. Domino | x | | x | | | x | | Haley R. Fisackerly | x | x | | x | | | J. Wayne Leonard | x | | x | | x | | Hugh T. McDonald | x | x | | | | William M. Mohl | | | x | x | Richard J. SmithCharles L. Rice, Jr. | | x | x | x | | Roderick K. West | x | | x | x | | Roderick K West | x | x | | | |
For security and business reasons, Entergy Corporation permits Mr. Leonardits Chief Executive Officer to use its corporate aircraft for personal use at the expense of Entergy Corporation. The other Named Executive Officers may use the corporate aircraft for personal travel subject to the approval of Entergy Corporation'sCorporation’s Chief Executive Officer. The aggregate incremental aircraft usage cost associated with Mr. Leonard'sLeonard’s personal use of the corporate aircraft, including the costs associated with travel to outside board meetings, was $26,869$54,198 for fiscal year 2009.2012. The aggregate incremental aircraft usage cost associated with Mr. West’s personal use of the aircraft was $26,574. These amounts are reflected in column (i) and the total above. The incremental cost to Entergy Corporation for use of the corporate aircraft is based on the variable operational costs of each flight, including fuel, maintenance, flight crew travel expense, catering, communications, and fees, including flight planning, ground handling, and landing permits.
None of the other individual perquisites itemsreferenced above exceeded $25,000 for any of the other Named Executive Officers.
20092012 Grants of Plan-Based Awards
The following table summarizes award grants during 20092012 to the Named Executive Officers.
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | | Name (a) | | Grant Date (b) | | Thresh-old ($) (c) | | Target ($) (d) | | Maximum ($) (e) | | Threshold (#) (f) | | Target (#) (g) | | Maximum (#) (h) | | All Other Stock Awards: Number of Shares of Stock or Units (#) (3) (i) | | All Other Option Awards: Number of Securities Under-lying Options (#) (4) (j) | | Exercise or Base Price of Option Awards ($/Sh) (k) | | Grant Date Fair Value of Stock and Option Awards (5) (l) | | (a) Name | | | (b) Grant Date | | (c) Thresh- old ($) | | (d) Target ($) | | (e) Maximum ($) | | (f) Threshold (#) | | (g) Target (#) | | (h) Maximum (#) | | (i) All Other Stock Awards: Number of Shares of Stock or Units (#) (3) | | (j) All Other Option Awards: Number of Securities Under- lying Options (#) (4) | | (k) Exercise or Base Price of Option Awards ($/Sh) | | (l) Grant Date Fair Value of Stock and Option Awards (5) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Theodore H. Bunting, Jr. | | 1/29/09 | | - | | $210,268 | | $420,536 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $392,000 | | $784,000 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 200 | | 2,000 | | 5,000 | | | | | | | | $387,650 | | 1/26/12 | | | | | | | | 1,246 | | 4,983 | | 9,967 | | | | | | | | $334,409 | | | | 1/29/09 | | | | | | | | | | | | | | | | 12,000 | | $77.53 | | $143,280 | | 5/31/12 | | | | | | | | 449 | | 1,794 | | 3,588 | | | | | | | | $101,648 | | | | | | | | | | | | | | | | | | | | | | | | | | | E. Renae Conley | | 1/29/09 | | - | | $244,608 | | $489,216 | | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 200 | | 2,000 | | 5,000 | | | | | | | | $387,650 | | 1/26/12 | | | | | | | | | | | | | | 2,100 | | | | | | $149,730 | | | | 1/29/09 | | | | | | | | | | | | | | | | 12,500 | | $77.53 | | $149,250 | | 1/26/12 | | | | | | | | | | | | | | | | 9,000 | | $71.30 | | $84,780 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Leo P. Denault | | 1/29/09 | | - | | $441,000 | | $882,000 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $472,399 | | $944,798 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 480 | | 4,800 | | 12,000 | | | | | | | | $930,360 | | 1/26/12 | | | | | | | | 1,350 | | 5,400 | | 10,800 | | | | | | | | $362,394 | | | | 1/29/09 | | | | | | | | | | | | | | | | 45,000 | | $77.53 | | $537,300 | | 1/26/12 | | | | | | | | | | | | | | 4,000 | | | | | | $285,200 | | | | | | | | | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | | | | | | | | | 30,000 | | $71.30 | | $282,600 | | | | | | | | | | | | | | | | | | | | | | | | | | | Joseph F. Domino | | 1/29/09 | | - | | $158,877 | | $317,754 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $165,275 | | $330,550 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 90 | | 900 | | 2,250 | | | | | | | | $174,443 | | 1/26/12 | | | | | | | | 375 | | 1,500 | | 3,000 | | | | | | | | $100,665 | | | | 1/29/09 | | | | | | | | | | | | | | | | 4,500 | | $77.53 | | $53,730 | | 1/26/12 | | | | | | | | | | | | | | 700 | | | | | | $49,910 | | | | | | | | | | | | | | | | | | | | | | | | | | 5/31/12 | | | | | | | | | | | | | | 6,000(6) | | | | | | $387,180 | | | | | 1/26/12 | | | | | | | | | | | | | | | | 7,300 | | $71.30 | | $68,766 | | | | | | | | | | | | | | | | | | | | | | | | | | | Haley R. Fisackerly | | 1/29/09 | | - | | $110,000 | | $220,000 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $115,580 | | $231,160 | | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | 375 | | 1,500 | | 3,000 | | | | | | | | $100,665 | | | | 1/29/09 | | | | | | | | 90 | | 900 | | 2,250 | | | | | | | | $174,443 | | 1/26/12 | | | | | | | | | | | | | | 1,200 | | | | | | $85,560 | | | | 1/29/09 | | | | | | | | | | | | | | | | 3,800 | | $77.53 | | $45,372 | | 1/26/12 | | | | | | | | | | | | | | | | 4,600 | | $71.30 | | $43,332 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | | 1/29/09 | | - | | $1,549,800 | | $3,099,600 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $1,620,331 | | $3,240,662 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 2,250 | | 22,500 | | 56,250 | | | | | | | | $4,361,063 | | 1/26/12 | | | | | | | | 6,725 | | 26,900 | | 53,800 | | | | | | | | $1,805,259 | | | | 1/29/09 | | | | | | | | | | | | | | | | 125,000 | | $77.53 | | $1,492,500 | | 1/26/12 | | | | | | | | | | | | | | 11,600 | | | | | | $827,080 | | | | 12/3/09 | | | | | | | | | | | | | | 100,000 | | | | | | $8,106,000 | | 1/26/12 | | | | | | | | | | | | | | | | 89,000 | | $71.30 | | $838,380 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | | 1/29/09 | | - | | $161,066 | | $322,132 | | | | | | | | | | | | | | | | 1/26/12 | | - | | $168,400 | | $336,800 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 90 | | 900 | | 2,250 | | | | | | | | $174,443 | | 1/26/12 | | | | | | | | 375 | | 1,500 | | 3,000 | | | | | | | | $100,665 | | | | 1/29/09 | | | | | | | | | | | | | | | | 4,500 | | $77.53 | | $53,730 | | 1/26/12 | | | | | | | | | | | | | | 1,300 | | | | | | $92,690 | | | | | | | | | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | | | | | | | | | 4,600 | | $71.30 | | $43,332 | | Richard J. Smith | | 1/29/09 | | - | | $451,500 | | $903,000 | | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 480 | | 4,800 | | 12,000 | | | | | | | | $930,360 | | | | | | | | | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | | | | | | | | | 35,000 | | $77.53 | | $417,900 | | | | | | | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | 1/29/09 | | - | | $126,000 | | $252,000 | | | | | | | | | | | | | | | | | William M. Mohl | | | 1/26/12 | | - | | $205,350 | | $410,700 | | | | | | | | | | | | | | | | | | 1/29/09 | | | | | | | | 90 | | 900 | | 2,250 | | | | | | | | $174,443 | | 1/26/12 | | | | | | | | 600 | | 2,400 | | 4,800 | | | | | | | | $161,064 | | | | 1/29/09 | | | | | | | | | | | | | | | | 5,000 | | $77.53 | | $59,700 | | 1/26/12 | | | | | | | | | | | | | | 1,500 | | | | | | $106,950 | | | | | | | | | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | | | | | | | | | 7,400 | | $71.30 | | $69,708 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Alyson M. Mount | | | 1/26/12 | | - | | $168,000 | | $336,000 | | | | | | | | | | | | | | | | (7) | | | 5/31/12 | | | | | | | | 517 | | 2,067 | | 4,133 | | | | | | | | $138,716 | | | | | 5/31/12 | | | | | | | | 330 | | 1,319 | | 2,639 | | | | | | | | $74,735 | | | | | 1/26/12 | | | | | | | | | | | | | | 1,500 | | | �� | | | $106,950 | | | | | | | | | | | | | | | | | | | | | | | | | | Sallie T. Rainer (7) | | | 1/26/12 | | - | | $110,000 | | $220,000 | | | | | | | | | | | | | | | | | | | 5/31/12 | | | | | | | | 323 | | 1,292 | | 2,583 | | | | | | | | $86,706 | | | | | 5/31/12 | | | | | | | | 158 | | 633 | | 1,267 | | | | | | | | $35,866 | | | | | 1/26/12 | | | | | | | | | | | | | | 1,300 | | | | | | $92,690 |
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | | (a) Name | | (b) Grant Date | | (c) Thresh- old ($) | | (d) Target ($) | | (e) Maximum ($) | | (f) Threshold (#) | | (g) Target (#) | | (h) Maximum (#) | | (i) All Other Stock Awards: Number of Shares of Stock or Units (#) (3) | | (j) All Other Option Awards: Number of Securities Under- lying Options (#) (4) | | (k) Exercise or Base Price of Option Awards ($/Sh) | | (l) Grant Date Fair Value of Stock and Option Awards (5) | | | | | | | | | | | | | | | | | | | | | | | | | | Charles L. Rice, Jr. | | 1/26/12 | | - | | $100,840 | | $201,680 | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | 375 | | 1,500 | | 3,000 | | | | | | | | $100,665 | | | | 1/26/12 | | | | | | | | | | | | | | 1,050 | | | | | | $74,865 | | | | 1/26/12 | | | | | | | | | | | | | | | | 4,600 | | $71.30 | | $43,332 | | | | | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | 1/26/12 | | - | | $412,412 | | $824,824 | | | | | | | | | | | | | | | | | | 1/26/12 | | | | | | | | 1,350 | | 5,400 | | 10,800 | | | | | | | | $362,394 | | | | 1/26/12 | | | | | | | | | | | | | | 4,000 | | | | | | $285,200 | | | | 1/26/12 | | | | | | | | | | | | | | | | 30,000 | | $71.30 | | $282,600 | | | | | | | | | | | | | | | | | | | | | | | | |
| (1) | The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the ExecutiveAnnual Incentive Plan. The actual amounts awarded are reported in column (g) of the Summary Compensation Table. | | (2) | The amounts in columns (f), (g), and (h) represent the minimum, target, and maximum payment levels under the Long-Term Performance Unit Program. Performance under the program is measured by Entergy Corporation'sCorporation’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia UtilitiesUtility Index. If Entergy Corporation'sCorporation’s total shareholder return is not at least 25% of that for the Philadelphia UtilitiesUtility Index, there is no payout. Subject to achievement of performance targets, each unit will be converted into one share of Entergy Corporation’s common stock on the last day of the performance period (December 31, 2014.) Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock. | | (3) | The amounts in column (i) represent shares of restricted stock granted under the 2011 Equity Ownership Plan. Shares of restricted stock vest over a three-year period, have voting rights and accrue dividends during the vesting period. | | (4) | The amounts in column (j) represent options to purchase shares of Entergy Corporation’s common stock. The options vest one-third on each of the first through third anniversaries of the grant date and have a ten-year term from the date of grant. The options were granted under the 2011 Equity Ownership Plan. | | (5) | The amounts in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with FASB ASC Topic 718 and, in the case of the performance units, are based on the probable outcome of the applicable performance conditions. See Notes 4 and 5 to the Summary Compensation Table for a discussion of the relevant assumptions used in calculating the grant date fair value. | | (6) | In May 2012, Mr. Domino was awarded 6,000 restricted stock units under the 2011 Equity Ownership Plan. The restricted stock units will vest on May 31, 2014. | | (7) | With their promotions on May 31, 2012, Mr. Bunting, Ms. Mount, and Ms. Rainer received pro-rated performance unit awards under the 2011 – 2013 Long-Term Performance Unit Program. Subject to achievement of performance targets, each unit will be converted into the cash equivalent of one share of Entergy Corporation'sCorporation’s common stock on the last day of the performance period (December 31, 2011.2013.) | (3) | In December 2009, the Personnel Committee granted 100,000 restricted units to Mr. Leonard. The restricted units vest in two equal installments of 50,000 units each on December 3, 2011 and December 3, 2012. The restricted units were granted under the 2007 Equity Ownership Plan. | (4) | The amounts in column (j) represent options to purchase shares of Entergy Corporation's common stock. The options vest one-third on each of the first through third anniversaries of the grant date. The options have a ten-year term from the date of grant. The options were granted under the 2007 Equity Ownership Plan. | (5) | The amounts included in column (l) are valued based on the aggregate grant date fair value of the award calculated in accordance with accounting standards assuming the highest level of performance is achieved. See Note 12 to the Financial Statements for a discussion of the relevant assumptions used in calculating the grant date fair value. |
20092012 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes unexercised options, stock that has not vested, and equity incentive plan awards for each Named Executive Officer outstanding as of the end of 2009.2012.
| | | Option Awards | | Stock Awards | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Theodore H. | | - | | 12,000(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | - | | 9,000(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | Bunting, Jr. | | 6,000 | | 12,000(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | 2,266 | | 4,534(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 6,666 | | 3,334(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | 9,666 | | 4,834(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 5,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | 12,000 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 2,200 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | 18,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 1,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | | | | 200(4) | | $16,368 | | | | | | | | | | | | | | | | | | | 1,400(5) | | $114,576 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | E. Renae Conley | | - | | 12,500(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | | 5,200 | | 10,400(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | 10,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 6,667 | | 3,333(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | 5,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 7,050 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | 2,200 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 7,500 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | 1,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | 9,200 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | 1,246(4) | | $79,433 | | | | 12,000 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | | | | | | | | | | | | | | | 1,074(5) | | $68,468 | | | | | | | | | | | | | | | | | | 200(4) | | $16,368 | | | | | | | | | | | | 2,100(6) | | $133,875 | | | | | | | | | | | | | | | | | | | | | | 1,400(5) | | $114,576 | | | | | | | | | | | | 1,167(7) | | $74,396 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Leo P. Denault | | - | | 45,000(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | - | | 30,000(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 16,666 | | 33,334(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | 8,333 | | 16,667(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 40,000 | | 20,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | 33,333 | | 16,667(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 50,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | 45,000 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 35,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | 50,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 40,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | 60,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 676 | | - | | | | $52.40 | | 2/11/2012 | | | | | | | | | | 50,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 7,720 | | - | | | | $52.40 | | 1/25/2011 | | | | | | | | | | 35,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 9,800 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | 34,995 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | 19,656 | | - | | | | $41.69 | | 2/11/2012 | | | | | | | | | | | | | | | | | | | | | | | | 1,350(4) | | $86,063 | | | | 5,434 | | - | | | | $37.00 | | 1/25/2011 | | | | | | | | | | | | | | | | | | | | | | | | 1,475(5) | | $94,031 | | | | | | | | | | | | | | | | | | 480(4) | | $39,283 | | | | | | | | | | | | 4,000(6) | | $255,000 | | | | | | | | | | | | | | | | | | | | | | 3,900(5) | | $319,176 | | | | | | | | | | | | 3,334(7) | | $212,543 | | | | | | | | | | | | | | | | | | 24,000(6) | | $1,964,160 | | | | | | | | | | | | | | | | 8,000(8) | | $510,000 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Joseph F. Domino | | - | | 4,500(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | - | | 7,300(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 2,333 | | 4,667(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | 966 | | 1,934(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 8,000 | | 4,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | 3,066 | | 1,534(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 7,500 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | 4,500 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 10,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | 7,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 10,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | 12,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 10,500 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | 7,500 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | | | | | | | | | | | | | | | 90(4) | | $7,366 | | 10,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 700(5) | | $57,288 | | 10,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | | | | 375(4) | | $23,906 | | | | | | | | | | | | | | | | | | | 300(5) | | $19,125 | | | | | | | | | | | | | | | 700(6) | | $44,625 | | | | | | | | | | | | | | | | | | | 600(7) | | $38,250 | | | | | | | | | | | | | | | | | | | 6,000(9) | | $382,500 | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | Haley R. Fisackerly | | - | | 4,600(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 966 | | 1,934(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 6,000 | | 3,000(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 3,800 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 5,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 2,500 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 1,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | | | | | | | | | | | | | | | 375(4) | | $23,906 | | | | | | | | | | | | | | | | | | 300(5) | | $19,125 | | | | | | | | | | | | | | 1,200(6) | | $76,500 | | | | | | | | | | | | | | | | | | 600(7) | | $38,250 | | | | | | | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | | - | | 89,000(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 23,333 | | 46,667(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 90,000 | | 45,000(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 125,000 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 175,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 255,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 210,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 165,200 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 220,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | | | 6,725(4) | | $428,719 | | | | | | | | | | | | | | | | | | 6,500(5) | | $414,375 | | | | | | | | | | | | | | 11,600(6) | | $739,500 | | | | | | | | | | | | | | | | | | 7,667(7) | | $488,771 | | | | | | | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | | - | | 4,600(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 966 | | 1,934(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 3,066 | | 1,534(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 4,500 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 7,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 12,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 7,500 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 10,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 375(4) | | $23,906 | | | | | | | | | | | | | | | | | | 300(5) | | $19,125 | | | | | | | | | | | | | | 1,300(6) | | $82,875 | | | | | | | | | | | | | | | | | | 600(7) | | $38,250 | | | | |
| | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | | | | | | | | | | | | | | | | | | | | | William M. Mohl | | - | | 7,400(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 2,033 | | 4,067(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 6,000 | | 3,000(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 7,500 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 9,300 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 3,500 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 5,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 3,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 600(4) | | $38,250 | | | | | | | | | | | | | | | | | | 625(5) | | $39,844 | | | | | | | | | | | | | | 1,500(6) | | $95,625 | | | | | | | | | | | | | | | | | | 734(7) | | $46,793 | | | | | | | | | | | | | | | | | | | | | | | | | | Alyson M. Mount | | 4,333 | | 2,167(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 4,500 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 4,500 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 5,400 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 5,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 4,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 1,500 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | | | 517(4) | | $32,959 | | | | | | | | | | | | | | | | | | 330(5) | | $21,038 | | | | | | | | | | | | | | 1,500(6) | | $95,625 | | | | | | | | | | | | | | | | | | 467(7) | | $29,771 | | | | | | | | | | | | | | | | | | | | | | | | | | Sallie T. Rainer | | 1,666 | | 834(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 1,200 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 2,300 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 2,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 2,500 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 2,500 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 1,900 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | | | | | | | | | | | | | | | 323(4) | | $20,591 | | | | | | | | | | | | | | | | | | 158(5) | | $10,073 | | | | | | | | | | | | | | 1,300(6) | | $82,875 | | | | | | | | | | | | | | | | | | 334(7) | | $21,293 | | | | | | | | | | | | | | | | | | | | | | | | | | Charles L. Rice, Jr. | | - | | 4,600(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 966 | | 1,934(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | | | | | | | | | | | | | | | 375(4) | | $23,906 | | | | | | | | | | | | | | | | | | 300(5) | | $19,125 | | | | | | | | | | | | | | 1,050(6) | | $66,938 | | | | | | | | | | | | | | | | | | 434(7) | | $27,668 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | - | | 30,000(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 5,666 | | 11,334(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 4,666 | | 2,334(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 5,000 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 8,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 12,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 1,334 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 667 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 1,350(4) | | $86,063 | | | | | | | | | | | | | | | | | | 1,475(5) | | $94,031 | | | | | | | | | | | | | | 4,000(6) | | $255,000 | | | | | | | | | | | | | | | | | | 2,000(7) | | $127,500 | | | | | | | | | | | | | | | | | | 15,000(10) | | $956,250 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | Haley R. Fisackerly | | - | | 3,800(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 1,666 | | 3,334(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 1,666 | | 834(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 1,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | | | | | | | | | | | | | | | 90(4) | | $7,366 | | | | | | | | | | | | | | | | | | 583(5) | | $47,713 | | | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | | - | | 125,000(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 58,333 | | 116,667(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 170,000 | | 85,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 210,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 165,200 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 220,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | 195,000 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | | | 330,600 | | - | | | | $41.69 | | 2/11/2012 | | | | | | | | | | | | 330,600 | | - | | | | $37.00 | | 1/25/2011 | | | | | | | | | | | | | | | | | | | | | | | | | | 2,250(4) | | $184,140 | | | | | | | | | | | | | | | | | | 16,500(5) | | $1,350,360 | | | | | | | | | | | | | | 100,000(7) | | $8,184,000 | | | | | | | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | | - | | 4,500(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 2,333 | | 4,667(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 8,000 | | 4,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 7,500 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 12,522 | | - | | | | $73.25 | | 2/11/2012 | | | | | | | | | | | | 10,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 10,000 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | 12,000 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | | | | | | | | | | | | | | | | | 90(4) | | $7,366 | | | | | | | | | | | | | | | | | | 700(5) | | $57,288 | | | | | | | | | | | | | | | | | | | | | | Richard J. Smith | | - | | 35,000(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 11,666 | | 23,334(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 40,000 | | 20,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 50,000 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 40,000 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | 63,600 | | - | | | | $58.60 | | 3/02/2014 | | | | | | | | | | | | 7,640 | | - | | | | $51.50 | | 1/25/2011 | | | | | | | | | | | | 50,000 | | - | | | | $44.45 | | 1/30/2013 | | | | | | | | | | | | 70,000 | | - | | | | $41.69 | | 2/11/2012 | | | | | | | | | | | | 39,428 | | - | | | | $37.00 | | 1/25/2011 | | | | | | | | | | | | | | | | | | | | | | | | | | 480(4) | | $39,283 | | | | | | | | | | | | | | | | | | 3,900(5) | | $319,176 | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | - | | 30,000(1) | | | | $71.30 | | 1/26/2022 | | | | | | | | | | | | 5,666 | | 11,334(2) | | | | $72.79 | | 1/27/2021 | | | | | | | | | | | | 4,666 | | 2,334(3) | | | | $77.10 | | 1/28/2020 | | | | | | | | | | | | 5,000 | | - | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 8,000 | | - | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 12,000 | | - | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 1,334 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 667 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 1,350(4) | | $86,063 | | | | | | | | | | | | | | | | | | 1,475(5) | | $94,031 | | | | | | | | | | | | | | 4,000(6) | | $255,000 | | | | | | | | | | | | | | | | | | 2,000(7) | | $127,500 | | | | | | | | | | | | | | | | | | 15,000(10) | | $956,250 | | | | | | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards | (a) Name | | (b) Number of Securities Underlying Unexercised Options (#) Exercisable | | (c) Number of Securities Underlying Unexercised Options (#) Unexercisable | | (d) Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options (#) | | (e) Option Exercise Price ($) | | (f) Option Expiration Date | | (g) Number of Shares or Units of Stock That Have Not Vested (#) | | (h) Market Value of Shares or Units of Stock That Have Not Vested ($) | | (i) Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested (#) | | (j) Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested ($) | | | | | | | | | | | | | | | | | | | | | | Roderick K. West | | - | | 5,000(1) | | | | $77.53 | | 1/29/2019 | | | | | | | | | | | | 2,666 | | 5,334(2) | | | | $108.20 | | 1/24/2018 | | | | | | | | | | | | 8,000 | | 4,000(3) | | | | $91.82 | | 1/25/2017 | | | | | | | | | | | | 1,334 | | - | | | | $68.89 | | 1/26/2016 | | | | | | | | | | | | 667 | | - | | | | $69.47 | | 1/27/2015 | | | | | | | | | | | | | | | | | | | | | | | | | | 90(4) | | $7,366 | | | | | | | | | | | | | | | | | | 700(5) | | $57,288 | | | | | | | | | | | | | | 15,000(8) | | $1,227,600 | | | | |
| (1) | Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/29/2010,26/2013, 1/29/201126/2014, and 1/29/2012.26/2015. | | | | | (2) | Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/24/201027/2013 and 1/24/2011.27/2014. | | | | | (3) | The remaining unexercisable options will vestvested on 1/25/2010.28/2013. | | | | | (4) | Consists of performance units that will vest on December 31, 2011 only if, and to2014 based on Entergy Corporation’s total shareholder return performance over the extent that, Entergy Corporation satisfies2012 – 2014 performance conditionsperiod as described under "Long-Term“Long-Term Compensation – Performance Unit Program"Program” in Compensation Discussion and Analysis. | | | | | (5) | Consists of performance units that will vest on December 31, 2010 only if, and to2013 based on Entergy Corporation’s total shareholder return performance over the extent that, Entergy Corporation satisfies2011 – 2013 performance conditions as described under "Long-Term Compensation – Performance Unit Program" in Compensation Discussion and Analysis.period. | | | | | (6) | Consists of shares of restricted stock that vested or will vest as follows: 1/3 of the shares of restricted stock granted vest on each of 1/26/2013, 1/26/2014, and 1/26/2015. | | | | | (7) | Consists of shares of restricted stock that vested or will vest as follows: 1/2 of the shares of restricted stock granted vest on each of 1/27/2013 and 1/27/2014. | | | | | (8) | Consists of restricted stock units granted under the 2007 Equity Ownership and Long-Term Cash Incentive Plan of Entergy Corporation and Subsidiaries or “2007 Equity Ownership Plan. 8,000” The units will vestvested on each of January 25, 2011, 2012 and 2013. | | | | (7)(9) | Consists of restricted stock units granted under the 20072011 Equity Ownership Plan 50,000 of which will vest on December 3, 2011 and the remaining 50,000 will visit on December 3, 2012.May 31, 2014. | | | | (8)(10) | Consists of restricted stock units granted under the 2007 Equity Ownership Plan which will vest on April 8,30, 2013. | | | |
20092012 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 20092012 for the Named Executive Officers.
| | | Options Awards | | Stock Awards | | Options Awards | | Stock Awards | (a) Name | | (b) Number of Shares Acquired on Exercise (#) | | (c) Value Realized on Exercise ($) | | (d) Number of Shares Acquired on Vesting (#) (1) | | (e) Value Realized on Vesting ($) | | (b) Number of Shares Acquired on Exercise (#) | | (c) Value Realized on Exercise ($) | | (d) Number of Shares Acquired on Vesting (#) | | (e) Value Realized on Vesting ($) | | | | | | | | | | | | | | | | | | | | Theodore H. Bunting, Jr. | | - | | - | | 1,139 | | $93,216 | | - | | $ - | | 611 | | $43,208 | | | | | | | | | | | | | E. Renae Conley | | 4,546 | | $124,347 | | 1,322 | | $108,192 | | | | | | | | | | | | | | | | | | | | | Leo P. Denault | | 12,404 | | $322,969 | | 2,834 | | $231,935 | | 17,633 | | $469,305 | | 9,748(1) | | $690,593 | | | | | | | | | | | | | | | | | | | | Joseph F. Domino | | - | | - | | 630 | | $51,559 | | 10,500 | | $291,857 | | 314 | | $22,234 | | | | | | | | | | | | | | | | | | | | Haley R. Fisackerly | | - | | - | | 315 | | $25,780 | | - | | $ - | | 314 | | $22,234 | | | | | | | | | | | | | | | | | | | | J. Wayne Leonard | | 330,600 | | $18,723,928 | | 64,988(2) | | $5,275,618 | | 195,000 | | $5,564,637 | | 54,022(2) | | $3,453,577 | | | | | | | | | | | | | | | | | | | | Hugh T. McDonald | | 9,199 | | $311,553 | | 630 | | $51,559 | | 10,000 | | $87,966 | | 314 | | $22,234 | | | | | | | | | | | | | | | | | | | | Richard J. Smith | | 40,137 | | $1,091,955 | | 2,834 | | $231,935 | | | William M. Mohl | | | - | | $ - | | 384 | | $27,126 | | | | | | | | | | | | | Alyson M. Mount | | | 1,800 | | $44,447 | | 244 | | $17,269 | | | | | | | | | | | | | Sallie T. Rainer | | | 1,000 | | $12,838 | | 174 | | $12,303 | | | | | | | | | | | | | Charles L. Rice, Jr. | | | - | | $ - | | 226 | | $16,009 | | | | | | | | | | | | | | | | | | | | Roderick K. West | | - | | - | | 630 | | $51,559 | | - | | $ - | | 1,049 | | $74,114 |
| (1) | RepresentsIncludes the vestingJanuary 25, 2012 cash settlement of performance8,000 restricted stock units forgranted under the 2007 - 2009 performance period (payable solely in cash based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program.Equity Ownership Plan. | | (2) | Amount includesIncludes the AugustDecember 3, 20092012 cash settlement of 50,000 restricted stock units granted under the 2007 Equity Ownership Plan. |
20092012 Pension Benefits
The following table shows the present value as of December 31, 2009,2012, of accumulated benefits payable to each of the Named Executive Officers, including the number of years of service credited to each Named Executive Officer, under the retirement plans sponsored by Entergy Corporation, determined using interest rate and mortality rate assumptions set forth in Note 11 to the Financial Statements.financial statements. Information regarding these retirement plans is included in Compensation Discussion & Analysis under the heading, "Benefits,“Benefits, Perquisites, Agreements, and Post-Retirement Plans - - Pension Plan, Pension Equalization Plan, and System Executive Retirement Plan."” In addition, this section includes information regarding early retirement options under the plans. Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2009 | | Theodore H. Bunting, Jr. (1) | | Non-qualified System Executive Retirement Plan | | 21.86 | | $1,479,700 | | $ - | | | | | Qualified defined benefit plan | | 21.11 | | $320,100 | | $ - | | | | | | | | | | | | | E. Renae Conley (2) | | Non-qualified Pension Equalization Plan | | 27.35 | | $1,325,300 | | $ - | | | | | Qualified defined benefit plan | | 10.83 | | $197,700 | | $ - | | | | | | | | | | | | | Leo P. Denault (3) | | Non-qualified System Executive Retirement Plan | | 25.83 | | $3,239,300 | | $ - | | | | | Qualified defined benefit plan | | 10.83 | | $155,900 | | $ - | | | | | | | | | | | | | Joseph F. Domino (1) | | Non-qualified System Executive Retirement Plan | | 39.56 | | $1,615,100 | | $ - | | | | | Qualified defined benefit plan | | 36.13 | | $997,500 | | $ - | | | | | | | | | | | | | | Haley R. Fisackerly | | Non-qualified System Executive Retirement Plan | | 14.08 | | $284,400 | | $ - | | | | | Qualified defined benefit plan | | 14.08 | | $149,300 | | $ - | | | | | | | | | | | | | J. Wayne Leonard (4) | | Non-qualified supplemental retirement plan benefit | | 11.68 | | $24,323,900 | | $ - | | | | | Qualified defined benefit plan | | 11.68 | | $285,900 | | $ - | | | | | | | | | | | | | Hugh T. McDonald (1) | | Non-qualified System Executive Retirement Plan | | 27.93 | | $918,800 | | $ - | | | | | Qualified defined benefit plan | | 26.44 | | $411,300 | | $ - | | | | | | | | | | | | | Richard J. Smith (5) | | Non-qualified Pension Equalization Plan | | 33.25 | | $3,701,700 | | $ - | | | | | Qualified defined benefit plan | | 10.33 | | $241,300 | | $ - | | | | | | | | | | | | | | Roderick K. West | | Non-qualified System Executive Retirement Plan | | 10.75 | | $334,600 | | $ - | | | | | Qualified defined benefit plan | | 10.75 | | $90,600 | | $ - | | | (1) | Service under the non-qualified System Executive Retirement Plan is granted from date of hire. Qualified plan benefit service is granted from the later of date of hire or plan participation date. | | (2) | Ms. Conley entered into an agreement granting 16.52 additional years of service under the non-qualified Pension Equalization Plan increasing the present value of the accumulated benefit by $26,000 over the benefit she would receive under the non-qualified System Executive Retirement Plan. | | (3) | During 2006, Mr. Denault entered into an agreement granting an additional 15 years of service under the non-qualified System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. The additional 15 years of service increases the present value of his benefit by $1,431,700. |
Name | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2011 | | Theodore H. Bunting, Jr. | | Non-qualified System Executive Retirement Plan | | 24.86 | | $2,708,600 | | $ - | | | | Qualified defined benefit plan | | 24.86 | | $739,400 | | $ - | | | | | | | | | | | Leo P. Denault (1) | | Non-qualified System Executive Retirement Plan | | 28.83 | | $5,479,100 | | $ - | | | | Qualified defined benefit plan | | 13.83 | | $397,500 | | $ - | | | | | | | | | | | Joseph F. Domino (2) | | Non-qualified System Executive Retirement Plan | | 42.56 | | $1,980,800 | | $ - | | | | Qualified defined benefit plan | | 39.13 | | $1,735,500 | | $ - | | | | | | | | | | | | Haley R. Fisackerly | | Non-qualified System Executive Retirement Plan | | 17.08 | | $803,700 | | $ - | | | | Qualified defined benefit plan | | 17.08 | | $400,600 | | $ - | | | | | | | | | | | J. Wayne Leonard (3) | | Non-qualified supplemental retirement plan benefit | | 14.68 | | $32,027,000 | | $ - | | | | Qualified defined benefit plan | | 14.68 | | $686,100 | | $ - | | | | | | | | | | | Hugh T. McDonald (2) | | Non-qualified System Executive Retirement Plan | | 30.93 | | $1,581,500 | | $ - | | | | Qualified defined benefit plan | | 29.44 | | $891,500 | | $ - | | | | | | | | | | | | William M. Mohl | | Non-qualified System Executive Retirement Plan | | 10.44 | | $1,119,300 | | $ - | | | | Qualified defined benefit plan | | 10.44 | | $301,900 | | $ - | | | | | | | | | | | | Alyson M. Mount | | Non-qualified System Executive Retirement Plan | | 10.35 | | $354,100 | | $ - | | | | Qualified defined benefit plan | | 10.35 | | $198,000 | | $ - | | | | | | | | | | | Sallie T. Rainer (2) | | Non-qualified System Executive Retirement Plan | | 28.38 | | $496,100 | | $ - | | | | Qualified defined benefit plan | | 26.52 | | $742,000 | | $ - | | | | | | | | | | | | Charles L. Rice, Jr. | | Non-qualified System Executive Retirement Plan | | 3.47 | | $129,500 | | $ - | | | | Qualified defined benefit plan | | 3.47 | | $80,500 | | $ - | | | | | | | | | | | | Roderick K. West | | Non-qualified System Executive Retirement Plan | | 13.75 | | $2,007,400 | | $ - | | | | Qualified defined benefit plan | | 13.75 | | $280,600 | | $ - | | | | | | | | | | |
(4)(1) | During 2006, Mr. Denault entered into an agreement granting an additional 15 years of service under the non-qualified System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. The additional 15 years of service increases the present value of his benefit by $1,727,800. | | (2) | Service under the non-qualified System Executive Retirement Plan is granted from date of hire. Qualified plan benefit service is granted from the later of date of hire or plan participation date. | | (3) | Pursuant to his retention agreement, Mr. Leonard is entitled to a non-qualified supplemental retirement benefit in lieu of participation in Entergy Corporation'sCorporation’s non-qualified supplemental retirement plans such as the System Executive Retirement Plan or the Pension Equalization Plan. Mr. Leonard may separate from employment without a reduction in his non-qualified supplemental retirement benefit. | (5) | Mr. Smith entered into an agreement granting 22.92 additional years of service under the non-qualified Pension Equalization Plan providing an additional $999,300 above the accumulated benefit he would receive under the non-qualified System Executive Retirement Plan. |
Qualified Retirement Benefits
The qualified retirement plan is a funded, tax-qualified, noncontributory defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of Entergy System companies. All Named Executive Officers are participants in this plan. TheBenefits under the tax-qualified pension plan provides a monthly benefitare calculated as an annuity payable for the participant's lifetime beginning at age 65 and equal to 1.5% of thea participant's five-year average monthly eligible earnings times such participant'sEligible Earnings multiplied by years of service. “Eligible Earnings” generally includes the employee’s salary and eligible incentive awards, other than incentive awards paid under the Annual Incentive Plan for the highest consecutive 60 months during the 120 months preceding termination of employment. Benefits under the tax-qualified plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company. The amount of annual earnings that may be considered in calculating benefits under the tax-qualified pension plan is limited by federal law. Years of service under the pension plan formula cannot exceed 40. Participants are 100% vested in their benefit upon completing 5 years of vesting service. Contributions to the pension plan are made entirely by Entergy Corporation and are paid into a trust fund from which the benefits of participants will be paid.
Normal retirement under the plan is age 65. Employees who terminate employment prior to age 55 may receive a reduced deferred vested retirement benefit payable as early as age 55 that is actuarially equivalent to the normal retirement benefit (i.e., reduced by 7% per year for the first 5 years preceding age 65, and reduced by 6% for each additional year thereafter). Employees who are at least age 55 with 10 years of vesting service upon termination from employment are entitled to a subsidized early retirement benefit beginning as early as age 55. The subsidized early retirement benefit is equal to the normal retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.
Mr. Domino Mr. Leonard and Mr. SmithLeonard are eligible for subsidized early retirement benefits.
NonqualifiedNon-qualified Retirement Benefits
The Named Executive Officers are eligible to participate in certain nonqualifiednon-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan and the System Executive Retirement Plan. Each of these plans is an unfunded nonqualifiednon-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, eachas described below, and in Compensation Discussion and Analysis, an executive is typically enrolled in one or more plans but only paid the amount due under the plan that provides the highest benefit. In general, upon disability, participants in the Pension Equalization Plan and the System Executive Retirement Plan remain eligible for continued service credits until recovery or retirement. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant'sparticipant’s accrued benefit.
All of the Named Executive Officers (other than Mr. Leonard) participate in both the Pension Equalization Plan and the System Executive Retirement Plan.
The Pension Equalization Plan
AllThe Pension Equalization Plan is a non-qualified unfunded supplemental retirement plan that provides for the payment to participants from Entergy's general assets a single lump sum cash distribution upon separation from service generally equal to the actuarial present value of the Named Executive Officers (withdifference between the exception of Mr. Leonard) are participants inamount that would have been payable as an annuity under the Pension Equalization Plan. The benefit provisions are substantially the same as the qualified retirementtax-qualified pension plan, but provide two additional benefits: (a) "restorative benefits" intended to offsetfor Internal Revenue Code limitations on certainpension benefits and earnings that may be considered in connection withcalculating tax-qualified pension benefits, and the qualified retirement planamount actually payable as an annuity under the tax-qualified pension plan. The Pension Equalization Plan also takes into account as “Eligible Earnings” any incentive awards paid under the Annual Incentive Plan and (b) supplemental credited service (ifif granted to an individual participant).participant provides supplemental credited service. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The benefits under this plan are offset by benefits payable from the qualified retirement plan and may be offset by prior employer benefits. Participants receive their Pension Equalization Plan benefit in the form of a single sum cash distribution. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the approval of the Entergy System company employer (which approval is deemed given following a change in control), an employee who terminates employment prior to age 65 may be vested in his or her benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits.
The System Executive Retirement Plan
All Named Executive Officers (except Mr. Leonard) are participants in the System Executive Retirement Plan. The System Executive Retirement Plan provides for a single sum payment at age 65, as further described in Compensation Discussion65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to participants from Entergy’s general assets of a single-sum cash distribution upon separation from service. The single-sum benefit is generally equal to the actuarial present value of a specified percentage of the participant’s “Final Average Monthly Compensation” (which is generally 1/36th of the sum of the participant's annual rate of base salary and Analysis. Annual Incentive Plan award for the 3 highest years during the last 10 years preceding termination of employment), after first being reduced by the value of the participant’s tax-qualified Pension Plan benefit and typically any prior employer pension benefit available to the participant.
While the System Executive Retirement Plan has a replacement ratio schedule from one year of service to the maximum of 30 years of service, the table below offers a sample ratio at 20 and 30 years of service.
Years of Service | Executives at Management Level 1 | Executives at Management Levels 2 and 3 – includes the remaining 4 Named Executive Officers | Executives at Management Level 4 | | 20 Years | 55.0% | 50.0% | 45.0% | | 30 years | 65.0% | 60.0% | 55.0% |
The System Executive Retirement Plan benefit is not vested until age 65. Subject to the approval of the Entergy System company employer, an employee who terminates his or her employment prior to age 65 may be vested in the System Executive Retirement Plan benefit, with payment of the lump sum benefit generally at separation from service unless delayed six months under Internal Revenue Code Section 409A. Benefits payable prior to age 65 are subject to the same reductions as qualified plan benefits. Further, in the event of a change in control, participants whose employment is terminated without “Cause” or for “Good Reason,” as defined in the Plan are also eligible for a subsidized lump sum benefit payment, even if they do not currently meet the age or service requirements for early retirement under that plan or have company permission to separate from employment. Such lump sum benefit is payable generally at separation from service unless delayed 6 months under Internal Revenue Code Section 409A.
Mr. Leonard's NonqualifiedLeonard’s Non-qualified Supplemental Retirement Benefit
Mr. Leonard'sLeonard’s retention agreement provides that if his employment with the Company is terminated for any reason other than for cause (as defined below under “Potential Payments Upon Termination or Change in Control”), he will be entitled to a non-qualified supplemental retirement benefit in lieu of participation in Entergy Corporation'sCorporation’s non-qualified supplemental retirement plans such as the System Executive Retirement Plan or the Pension Equalization Plan. Mr. Leonard'sLeonard’s non-qualified supplemental retirement benefit is calculated as a single life annuity equal to 60% of his final three-year average compensation (as described in the description of the System Executive Retirement Plan included in the Compensation Discussion and Analysis)above), reduced to account for benefits payable to Mr. Leonard under Entergy Corporation'sCorporation’s and a former employer'semployer’s qualified pension plans. The benefit is payable in a single lump sum. BecauseAt December 31, 2012, Mr. Leonard hashad already attained the age of 55, he is currentlyand was entitled under his retention agreement to his non-qualified supplemental retirement benefit if he were to leave Entergy System company employment other than as the result of a termination for cause.
Additional Information
For a description of the material terms and conditions of payments and benefits available under the Mr. Leonard became eligible to receive this retirement plans, including each plan's normal retirement payment and benefit benefit formula and eligibility standards, specific elements of compensation included in applying the payment and benefit formula, and Entergy Corporation's policies with regard to granting extra years of credited service, see "Compensation Discussion and Analysis -- Benefits, Perquisites, Agreements and Post-Termination Plans -- Pension Plan, Pension Equalization Plan and System Executive Retirement Plan." For a discussion of the relevant assumptions used in valuing these liabilities, see Note 11 to the Financial Statements.
upon his retirement.
2009 Nonqualified2012 Non-qualified Deferred Compensation
The following tables provide information regarding the Executive Deferred Compensation Plan, the Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (the 1998 Equity Ownership Plan) and the 2007 Equity Ownership Plan whichand the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers. For additional information, see "Benefits, Perquisites, Agreements and Post-Termination Plans -Entergy Corporation does not “match” amounts that are deferred by employees pursuant to the Executive Deferred Compensation" in Compensation DiscussionPlan or the equity plans. With the exception of allowing for the deferral of federal and Analysis. Allstate taxes, Entergy Corporation provides no additional benefit to the Named Executive Officers are eligible to participateOfficer for deferring any of the compensation received under these plans. Any increase in value of the deferral programs.
Additionally, somedeferred amounts results solely from the increase in value of the deemed investment options selected by the Named Executive Officer (phantom stock of Entergy Corporation or mutual funds available under the Savings Plan). As of December 31, 2012 none of the Named Executive Officers havehad deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.
As of December 31, 2012, Mr. Leonard had a deferred account balancesbalance under a frozen Defined Contribution Restoration Plan. These amounts are deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to participants under the options available under this Defined Contribution RestorationSavings Plan. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible employees'employees’ deferral accounts with employer contributions to the extent contributions under the qualified savings plan in which the employee participated were subject to limitations imposed by the Internal Revenue Code.
All deferrals are credited to the applicable Entergy System company employer'semployer’s non-funded liability account. Depending on the plan under which the deferral is made, the Named Executive Officers may elect investment in either phantom Entergy Corporation common stock or one or more of several investment options available under the Savings Plan. Within limitations of the program, participating Named Executive Officers may move funds from one deemed investment option to another. The participating Named Executive Officers do not have the ability to withdraw funds from the deemed investment accounts except within the terms provided in their deferral elections. Within the limitations prescribed by law as well as the program,plan, participating Named Executive Officers with deferrals under the Executive Deferred Compensation Plan and/or the equity plans have the option to make a successive deferral of these funds. Assuming a Named Executive Officer does not elect a successive deferral, the Entergy System company employer of the participant is obligated to pay the amount credited to the participant'sparticipant’s account at the earlier of deferral receipt date or separation from service. These payments are paid out of the general assets of the employer and are payable in a lump sum.
FICA and Medicare taxes are paid on all deferred amounts prior to their deferral. Applicable federal and state taxes are paid at the time the deferred amounts are paid to the participant. Employees are not eligible for a "match" of amounts that are deferred by them pursuant to the deferred compensation programs. With the exception of allowing for the deferral of federal and state taxes, the Entergy System company employer provides no additional benefit to the Named Executive Officers in connection with amounts deferred under the Executive Deferred Compensation Plan. The deemed investment options available to participating Named Executive Officers are limited to certain deemed investment options available to all non-officer employees under the Savings Plan. Deferred amounts are deemed credited with earnings or losses based on the rate of return of deemed investment options (under the Executive Deferred Compensation Plan) or Entergy Corporation common stock (under the Equity Ownership Plan or 2007 Equity Plan). In 2006, the Personnel Committee approved a number of recommendations to simplify the deferral programs and reduce the number of options available to the Named Executive Officers.
Executive Deferred CompensationDefined Contribution Restoration Plan
Name (a) | | Executive Contributions in 2009 (b) | | Registrant Contributions in 2009 (c) | | Aggregate Earnings in 2009 (1) (d) | | Aggregate Withdrawals/ Distributions (e) | | Aggregate Balance at December 31, 2009 (2) (f) | | | | | | | | | | | | | | E. Renae Conley | | $ - | | $ - | | $7,105 | | ($574,905) | | $ - | | | | | | | | | | | | | | Joseph F. Domino | | $ - | | $ - | | $130 | | ($239,857) | | $ - | | | | | | | | | | | | | | J. Wayne Leonard | | $ - | | $ - | | $8,272 | | ($175,235) | | $203,900 | | | | | | | | | | | | | | Hugh T. McDonald | | $ - | | $ - | | $356 | | ($1,211,343) | | $ - | | | | | | | | | | | | | | Richard J. Smith | | $ - | | $ - | | $5,581 | | ($843,075) | | $ - | | | | | | | | | | | | |
(1) | Amounts in this column are not included in the Summary Compensation Table. | (2) | For Mr. Leonard, approximately $183,000 of the amount reported in this column has previously been reported in the Summary Compensation Table. |
Equity Ownership Plan
Name (a) | | Executive Contributions in 2009 (b) | | Registrant Contributions in 2009 (c) | | Aggregate Earnings in 2009 (1) (d) | | Aggregate Withdrawals/ Distributions (e) | | Aggregate Balance at December 31, 2009 (f) | | Executive Contributions in 2012 (b) | | Registrant Contributions in 2012 (c) | | Aggregate Earnings in 2012 (1) (d) | | Aggregate Withdrawals/ Distributions (e) | | Aggregate Balance at December 31, 2012 (f) | | | | | | | | | | | | | | | | | | | | | | | | E. Renae Conley | | $ - | | $ - | | $10,203 | | ($1,064,918) | | $ - | | | | | | | | | | | | | | | | J. Wayne Leonard | | $ - | | $ - | | $89,463 | | ($9,337,269) | | $ - | | $ - | | $ - | | ($18,761) | | $ - | | $208,570 | | | | | | | | | | | | | | | Hugh T. McDonald | | $ - | | $ - | | $14,690 | | ($1,533,205) | | $ - | | | | | | | | | | | | | | |
| (1) | Amounts in this column are not included in the Summary Compensation Table. |
Defined Contribution Restoration Plan
Name (a) | | Executive Contributions in 2009 (b) | | Registrant Contributions in 2009 (c) | | Aggregate Earnings in 2009 (1) (d) | | Aggregate Withdrawals/ Distributions (e) | | Aggregate Balance at December 31, 2009 (f) | | | | | | | | | | | | | | Theodore H. Bunting, Jr. | | $ - | | $ - | | $104 | | ($10,791) | | $ - | | | | | | | | | | | | | | E. Renae Conley | | $ - | | $ - | | $821 | | ($85,644) | | $ - | | | | | | | | | | | | | | Leo P. Denault | | $ - | | $ - | | $606 | | ($63,276) | | $ - | | | | | | | | | | | | | | Joseph F. Domino | | $ - | | $ - | | $339 | | ($32,811) | | $ - | | | | | | | | | | | | | | J. Wayne Leonard | | $ - | | $ - | | $5,520 | | $ - | | $232,665 | | | | | | | | | | | | | | Hugh T. McDonald | | $ - | | $ - | | $233 | | ($24,233) | | $ - | | | | | | | | | | | | | | Richard J. Smith | | $ - | | $ - | | $1,458 | | ($152,193) | | $ - | | | | | | | | | | | | |
(1) | Amounts in this column are not included in the Summary Compensation Table. |
2012 Potential Payments upon Termination or Change in Control
Estimated PaymentsEntergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment is terminated under specified conditions, including following a change in control of Entergy Corporation. In addition, Mr. Leonard and Mr. Denault have individual retention agreements.
The tables below reflect the amount of compensation each named executive officer would receive upon the occurrence of the specified separation triggering events, based on available programs and specific agreementsNamed Executive Officers would have received if his or her employment with each executive. The tables assume the separation was effective onan Entergy System company had been terminated under various scenarios as of December 31, 2009,2012. For purposes of these tables, the last business day of the last fiscal year, and theassumed stock price of Entergy Corporation common stock is $81.84, which was $63.75, the closing market price on suchthat date.
Theodore H. Bunting, Jr Senior ViceGroup President, Chief Accounting OfficerUtility Operations
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Senior ViceGroup President, Chief Accounting OfficerUtility Operations would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control | Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $2,679,040 | Performance Units:(3) | | | | | | | | | | 2011-2013 Performance Unit Program | --- | --- | --- | --- | $182,516 | $182,516 | --- | $227,269 | | 2012-2014 Performance Unit Program | --- | --- | --- | --- | $105,889 | $105,889 | --- | $227,269 | Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 | Unvested Restricted Stock(5) | --- | --- | --- | --- | $81,855 | $81,855 | --- | $222,843 | Medical and Dental Benefits(6) | --- | --- | --- | --- | --- | --- | --- | $25,614 | 280G Tax Gross-up(9) | --- | --- | --- | --- | --- | --- | --- | --- |
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control | Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $1,121,434 | Performance Units:(3) | | | | | | | | | | 2008-2010 Performance Unit Program | --- | --- | --- | --- | $76,384 | $76,384 | $114,576 | $114,576 | | 2009-2011 Performance Unit Program | --- | --- | --- | --- | $54,560 | $54,560 | $163,680 | $163,680 | Unvested Stock Options(4) | --- | --- | --- | --- | $51,720 | $51,720(7) | $51,720 | $51,720 | Medical and Dental Benefits (5) | --- | --- | --- | --- | --- | --- | --- | $23,730 | | 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | $1,354,235 |
1(1) | In addition to the payments and benefits in the table, Mr. Bunting also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009 Pension Benefits." Ifif Mr. Bunting's employment were terminated under certain conditions relating to a change in control, heMr. Bunting also would also behave been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, which are described in "2009see "2012 Pension Benefits." If Mr. Bunting's employment were terminated "forfor cause," he would forfeit his benefit under the System Executive Retirement Plan supplemental benefits.Plan. |
2(2) | In the event of a qualifying termination related to a change in control, Mr. Bunting would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to twothe product of 2.99 times the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated atusing the average annual target opportunity.opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $560,000 was assumed. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. Bunting would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, the value of Mr. Bunting's awards have beenBunting’s severance payment was calculated as follows: 2008 - 2010 Plan - 1,400by taking an average of the target performance units at target, assuming a stockfrom the 2008-2010 Performance Unit Program (2719 units) and the 2009-2011 Performance Unit Program (4,411 units). This average number of units (3,565 units) multiplied by the closing price of $81.84Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $227,269 for the forfeited performance units.
2009 - 2011 Plan - 2,000 performance units at target, assuming a stock priceIn the event of $81.84
For scenarios other than a terminationMr. Bunting’s death or disability not related to a change in control, the award isMr. Bunting would not enhanced or accelerated by the termination event. With respect to death or disability, the award ishave forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Bunting's awards were calculated as follows:
2011 - 2013 Plan – 2,863 (4,294 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 1,661 (4,983 * 12/36) performance units at target, assuming a stock price of $63.75 | 4(4) | In the event of his death, disability or a change in control, all of Mr. Bunting's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Bunting'sBunting’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Bunting exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for all of Mr. Bunting’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. | 5(5) | In the event of his death or disability, Mr. Bunting would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Bunting would immediately vest in all unvested restricted stock. | | (6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Bunting would be eligible to receive Company- subsidized medical and dentalCOBRA benefits for a period up to 18 months. |
6(7) | As of December 31, 2009,2012, compensation and benefits available to Mr. Bunting under this scenario are substantially the same as available with a voluntary resignation. | 7(8) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. | 8 | Under the 2007 Equity Ownership Plan,December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (based on the assumption that all performance goals were achieved at target).payable as described in footnote 3 above. |
E. Renae Conley
President and CEO, Entergy Gulf States Louisiana and Entergy Louisiana
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President & CEO, Entergy Gulf States Louisiana and Entergy Louisiana would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2009:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control | | | Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $1,304,575 | Performance Units:(3) | | | | | | | | | | 2008-2010 Performance Unit Program | --- | --- | --- | --- | $76,384 | $76,384 | $114,576 | $114,576 | | 2009-2011 Performance Unit Program | --- | --- | --- | --- | $54,560 | $54,560 | $163,680 | $163,680 | Unvested Stock Options(4) | --- | --- | --- | --- | $53,875 | $53,875(7) | $53,875 | $53,875 | Medical and Dental Benefits (5) | --- | --- | --- | --- | --- | --- | --- | $7,896 | | 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- |
1 | In additionThe 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying involuntary termination in order to the payments and benefits in the table, Ms. Conley also would have been entitled to receive her vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009 Pension Benefits." If Ms. Conley's employment were terminated under certain conditions relating toaccelerate vesting or trigger severance payment upon a change in control, she would also be eligible for early retirement benefits, which are described in "2009 Pension Benefits." If Ms. Conley's employment were terminated "for cause," she would forfeit her supplemental credited service and System Executive Retirement Plan supplemental benefits.control. | 2(9) | In the event of a termination related to a change in control, Ms. Conley would be entitled to receive pursuant toDecember 2010, the System Executive Continuity Plan a lump sum severance payment equalwas amended to two times her base salary plus annual incentive, calculated at target opportunity. | 3 | In the event of a termination related to a change in control, Ms. Conley would have been entitled to receive pursuant to the System Executive Continuity Plan a lump sum payment relating to her performance units. The payment is calculated as if all performance goals relating to the performance unit were achieved at target level. For purposes of the table, the value of Ms. Conley's awards have been calculated as follows:
2008 - 2010 Plan - 1,400 performance units at target, assuming a stock price of $81.84
2009 - 2011 Plan - 2,000 performance units at target, assuming a stock price of $81.84
For scenarios other than a termination related to a change in control, the award is not enhanced or accelerated by the termination event. With respect to death or disability, the award is pro-rated based on the number of months of participation in each Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
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4 | In the event of disability or a termination related to a change in control, all of Ms. Conley's unvested stock options would immediately vest. In addition, she would be entitled to exercise her stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Ms. Conley exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009, and the applicable exercise price of each option share. | 5 | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Conley would be eligible to receive subsidized medical and dental benefits for a period up to 18 months. | 6 | As of December 31, 2009, compensation and benefits available to Ms. Conley under this scenario are substantially the same as available with a voluntary resignation. | 7 | Under the 2007 Equity Ownership Plan (applicable to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. | 8 | Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control in the Company without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
·All unvested stock options would become immediately exercisable.
·All performance units become vested (based on the assumption that all performance goals were achieved at target).
eliminate excise tax gross-up payments. |
Leo P. Denault Executive Vice President and Chief Financial Officer The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Executive Vice President and Chief Financial Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(8) | Disability | Death (9) | Change in Control(10) | Termination Related to a Change in Control | | | | | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(9) | Disability | Death | Change in Control(10) | Termination Related to a Change in Control | Severance Payment(2) | --- | --- | $3,202,290 | --- | --- | $3,202,290 | --- | --- | $3,430,293 | --- | --- | --- | --- | $3,430,293 | Performance Units:(3) | | | | | | | | | | | | | | | | 2008-2010 Performance Unit Program | --- | --- | $319,176 | --- | $319,176 | $319,176 | | | 2009-2011 Performance Unit Program | --- | --- | $392,832 | --- | $392,832 | $392,832 | | | 2011-2013 Performance Unit Program | | --- | --- | $277,313 | --- | $277,313 | $277,313 | --- | $277,313 | | 2012-2014 Performance Unit Program | | --- | --- | $277,313 | --- | $277,313 | $277,313 | --- | $277,313 | Unvested Stock Options(4) | --- | --- | $193,950 | --- | $193,950 | $193,950 (9) | $193,950 | $193,950 | --- | --- | $0 | --- | $0 | $0 | --- | $0 | Unvested Restricted Stock(5) | | --- | --- | $502,622 | --- | $502,622 | $502,622 | -- | $502,622 | Unvested Restricted Units(5)(6) | --- | --- | $1,995,120 | --- | $1,995,120 | $1,995,120 | --- | | $510,000 | --- | $510,000 | $510,000 | -- | $510,000 | COBRA Benefits(6)(7) | --- | --- | $13,962 | --- | --- | --- | --- | --- | $25,614 | --- | --- | --- | --- | --- | Medical and Dental Benefits(7)(8) | --- | --- | --- | --- | --- | $13,962 | --- | --- | --- | --- | --- | --- | --- | $25,614 | | 280G Tax Gross-up | --- | --- | --- | --- | --- | $3,457,221 | | 280G Tax Gross-up(11) | | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. Denault also would have been entitled to receive his vested pension benefits. If Mr. Denault’s employment were terminated under certain conditions relating to a change in control, he would also be eligible for early retirement benefits. For a description of these benefits, see “2009“2012 Pension Benefits.” In addition, Mr. Denault is subject to the following provisions: ·Retention Agreement. Mr. Denault’s retention agreement provides that, unless his employment is terminated for cause, he will be granted an additional 15 years of service under the System Executive Retirement Plan if he continues to work for an Entergy System company employer until age 55. Because Mr. Denault had not reached age 55 as of December 31, 2009,2012, he is only entitled to this supplemental credited service and System Executive Retirement Plan supplemental benefits in the event of his death or disability.
·System Executive Retirement Plan. If Mr. Denault’s employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan. In the event of a termination related to a change in control, pursuant to the terms of the System Executive Retirement Plan, Mr. Denault would be eligible for subsidized retirement (but not the additional 15 years of service) upon his separation of service even if he does not then meet the age or service requirements for early retirement under the System Executive Retirement Plan or have company permission to separate from employment.
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2(2) | In the event of a termination related(not due to a change in controldeath or a terminationdisability) by Mr. Denault for good reason or by Entergythe Company not for cause (regardless of whether there is a change in control), Mr. Denault would be entitled to receive, pursuant to his retention agreement, a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the effective date of the Agreement (i.e., 2007) or, if higher, immediately prior to a circumstance constituting good reason plus (b) the greater of (i) his actual annual incentive calculated ataward under the Annual Incentive Plan for the calendar year immediately preceding the calendar year in which Mr. Denault’s termination date occurs or (ii) Mr. Denault’s Annual Incentive Plan target opportunity.award for the calendar year in which the effective date of the Agreement occurred (i.e., 2007). For purposes of this table, we have calculated the award at a 70% target opportunity and assumedwas calculated using a base salary of $630,000.$674,856 and target award of 70%. | 3(3) | In the event of a termination relateddue to death or disability, by Mr. Denault for good reason, or by the Company not for cause (in all cases, regardless of whether there is a change in control,control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-sum severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would be calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault's severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (3,900 units) and the 2009-2011 Performance Unit Program (4,800 units). This average number of units (4,350 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $277,313 for the forfeited performance units. | | (4) | In the event of his death, disability, termination by Mr. Denault for good reason or a termination by Entergy other thanthe Company not for cause disability or death, Mr. Denault would have been entitled to receive under the terms(regardless of his retention agreement a lump sum payment relating to his performance units. The paymentwhether there is calculated as if all performance goals relating to the performance units were achieved at target level. For purposes of the table, we have calculated the value of Mr. Denault’s awards as follows: 2008 - 2010 Plan – 3,900 performance units at target, assuming a stock price of $81.84
2009 - 2012 Plan – 4,800 performance units at target, assuming a stock price of $81.84
| 4 | In the event of disability or a termination related to a change in control,control), all of Mr. Denault’s unvested stock options would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. Further, pursuant to Mr. Denault’s retention agreement, in the event of a termination for good reason or other than for cause, all of Mr. Denault’s unvested stock options granted under the 2007 Equity Ownership Plan (applicable to grants of equity awards made after January 1, 2007) would immediately vest. For purposes of this table, weit was assumed that Mr. Denault exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2009,2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. Denault’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death, disability, termination by Mr. Denault for good reason or by the Company not for cause (regardless of whether there is a change in control), all of Mr. Denault’s unvested restricted stock would immediately vest. | 5
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(6) | Mr. Denault’s 24,0008,000 restricted units vest 1/3 in 2011, 1/3 in 2012 and 1/3 in 2013.on January 25, 2013, provided he remains a full-time Entergy System company employee through each such vesting date. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of change in control, termination related to a change in control, aMr. Denault’s death or disability, or termination of employment by Mr. Denault for good reason or a termination by Entergy other thanthe Company not for cause disability or death.(regardless of whether there is a change in control). |
| (7) | Pursuant to his retention agreement, in the event of a termination by Entergy other than cause or by Mr. Denault for good reason or by the Company not for cause, Mr. Denault would be eligible to receive company-subsidizedCompany-subsidized COBRA benefits for a period of 18 months. | 7(8) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Denault would be eligible to receive subsidizedCompany-subsidized medical and dental benefits for a period up to 18 months. | 8(9) | As of December 31, 2009, compensation and benefits available to2012, Mr. Denault under this scenario are substantially the same as available under a voluntary resignation.is not eligible for retirement. | 9(10) | Under theThe 2007 Equity Ownership Plan was amended in the event of a plan participant’s death, all unvested stock options would become immediately exercisable | 10 | Under the 2007 Equity Ownership Plan, plan participants are entitledDecember 2010 so that awards granted after December 30, 2010 require an involuntary termination in order to receive an acceleration of certain benefits based solelyaccelerate vesting or trigger severance payments upon a change in control in the Company without regardcontrol.
| | (11) | In December of 2010, Mr. Denault voluntarily agreed to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:amend his retention agreement to eliminate excise tax gross up payments. |
Under the terms of Mr. Denault’s retention agreement, Entergy may terminate his employment for cause upon Mr. Denault’s:
| · | continuing failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Personnel Committee; |
| · | willfully engaging in conduct that is demonstrably and materially injurious to Entergy; |
| · | conviction of or entrance of a plea of guilty or nolo contendere to a felony or other crime that has or may have a material adverse effect on his ability to carry out his duties or upon Entergy’s reputation; |
| · | material violation of any agreement that he has entered into with Entergy; or |
| · | unauthorized disclosure of Entergy’s confidential information. |
Mr. Denault may terminate his employment for good reason upon: | · | the substantial reduction in the nature or status of his duties or responsibilities; |
| · | a reduction of 5% or more in his base salary as in effect on the date of the retention agreement; |
| · | the relocation of his principal place of employment to a location other than the corporate headquarters; |
| · | the failure to continue to allow him to participate in programs or plans providing opportunities for equity awards, stock options, restricted stock, stock appreciation rights, incentive compensation, bonus and other plans on a basis not materially less favorable than enjoyed at the time of the retention agreement (other than changes similarly affecting all senior executives); |
| · | the failure to continue to allow him to participate in programs or plans with opportunities for benefits not materially less favorable than those enjoyed by him under any of ourthe pension, savings, life insurance, medical, health and accident, disability or vacation plans at the time of the retention agreement (other than changes similarly affecting all senior executives); or |
| · | any purported termination of his employment not taken in accordance with his retention agreement. |
Mr. Denault may terminate his employment for good reason in the event of a change in control upon: | · | the substantial reduction or alteration in the nature or status of his duties or responsibilities; |
| · | a reduction in his annual base salary; |
| · | the relocation of his principal place of employment to a location more than 20 miles from his current place of employment; |
| · | the failure to pay any portion of his compensation within seven days of its due date; |
| · | the failure to continue in effect any compensation plan in which he participates and which is material to his total compensation, unless other equitable arrangements are made; |
| · | the failure to continue to provide benefits substantially similar to those that he currently enjoys under any of the pension, savings, life insurance, medical, health and accident or disability plans, or Entergy taking of any other action which materially reduces any of those benefits or deprives him of any material fringe benefits that he currently enjoys; |
| · | the failure to provide him with the number of paid vacation days to which he is entitled in accordance with the normal vacation policy; or |
| · | any purported termination of his employment not taken in accordance with his retention agreementagreement. |
Joseph F. Domino President & CEO - Entergy TexasChief Integration Officer
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO – Entergy TXChief Integration Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012: Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(8) | Disability | Death | Change in Control(9) | Termination Related to a Change in Control | | | Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $495,825 | Performance Units:(3) | | | | | | | | | | 2011-2013 Performance Unit Program | --- | --- | --- | $51,000 | $51,000 | $51,000 | --- | $51,000 | | 2012-2014 Performance Unit Program | --- | --- | --- | $31,875 | $31,875 | $31,875 | --- | $51,000 | Unvested Stock Options(4) | --- | --- | --- | $0 | $0 | $0 | --- | $0 | Unvested Restricted Stock(5) | --- | --- | --- | --- | $34,170 | $34,170 | | $89,123 | Unvested Restricted Units(6) | --- | --- | $382,500 | --- | --- | --- | --- | $382,500 | Medical and Dental Benefits(7) | --- | --- | --- | --- | --- | --- | --- | --- | 280G Tax Gross-up(10) | --- | --- | --- | --- | --- | --- | --- | --- |
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control | | | | Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $476,631 | Performance Units:(3) | | | | | | | | | | 2008-2010 Performance Unit Program | --- | --- | --- | $38,192 | $38,192 | $38,192 | $57,288 | $57,288 | | 2009-2011 Performance Unit Program | --- | --- | --- | $24,552 | $24,552 | $24,552 | $73,656 | $73,656 | Unvested Stock Options(4) | --- | --- | --- | $19,395 | $19,375 | $19,395(7) | $19,375 | $19,395 | Medical and Dental Benefits (5) | --- | --- | --- | --- | --- | --- | --- | --- | | 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. Domino would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009"2012 Pension Benefits." If Mr. Domino's employment were terminated under certain conditions relatingIn the event of a termination related to a change in control, he would also be eligible for early retirement benefits, which are described in "2009 Pension Benefits." If Mr. Domino's employment were terminated "for cause," he would forfeit hispursuant to the terms of the System Executive Retirement Plan, and other similar supplemental benefits.Mr. Domino would be eligible for subsidized early retirement even if he does not have company permission to separate from employment.�� If Mr. Domino’s employment were terminated for cause, he would not receive a benefit under the System Executive Retirement Plan. |
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2(2) | In the event of a qualifying termination related to a change in control, Mr. Domino would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of one time the sum of (a) his annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated atusing the average annual target opportunity. opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 50% target opportunity and a base salary of $330,550 was assumed. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. Domino would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, the value of Mr. Domino's awardsDomino’s severance payment was calculated as follows:by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. 2008 - 2010 Plan – 700 performance units at target, assuming a stock priceIn the event of $81.84
2009 - 2012 Plan – 900 performance units at target, assuming a stock price of $81.84
For scenarios other than a terminationMr. Domino’s death or disability not related to a change in control, the award is not enhanced or accelerated by the termination event. With respect to death, disability or retirement (as Mr. Domino is eligiblewould not have forfeited his performance units for retirement), the award isall open performance periods, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Domino’s awards were calculated as follows:
2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75 |
4(4) | In the event of his retirement, death, disability or a change in control, all of Mr. Domino’s unvested stock options granted prior to December 31, 2010 would immediately vest. In the event of his retirement, death, disability or qualifying termination related to a change in control, all of Mr. Domino'sDomino’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of thea ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Domino exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Domino’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
5(5) | In the event of his death or disability, Mr. Domino would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Domino would immediately vest in all unvested restricted stock. |
| (6) | Mr. Domino's 6,000 restricted unit vest 100% on May 31, 2014 provided he remains a full-time Entergy System company employee through such vesting date. Pursuant to his restricted unit agreement, his unvested restricted units will vest immediately in the event of termination for good reason or not for cause or a termination related to change in control. |
| (7) | Upon retirement Mr. Domino would be eligible for retiree medical and dental benefits.benefits, the same as all other retirees. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Domino would not be eligible to receive additionalEntergy subsidized medical and dental benefits similar to those provided to a retiree.COBRA benefits. |
6(8) | As of December 31, 2009,2012, Mr. Domino is retirement eligible and would retire rather than voluntarily resign. Given that scenario, the compensation and benefits available to Mr. Domino under this scenarioretirement are substantially the same as available with a voluntary resignation. For information regarding these vested benefits, see the Pension Benefits table included in this Form 10-K. |
7(9) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. |
8 | Under the 2007 Equity Ownership Plan,December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (basedpayable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
| (10) | In December 2010, the assumption that all performance goals were achieved at target).System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
Haley R. Fisackerly
President & CEO, - Entergy Mississippi
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO, - Entergy Mississippi would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
| |
Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $404,530 |
Performance Units:(3) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | --- | $51,000 | $51,000 | --- | $51,000 |
| 2012-2014 Performance Unit Program | --- | --- | --- | --- | $31,875 | $31,875 | --- | $51,000 |
Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | --- | --- | --- | --- | $44,561 | $44,561 | --- | $122,636 |
Medical and Dental Benefits(6) | --- | --- | --- | --- | --- | --- | --- | $17,076 |
280G Tax Gross-up(9) | --- | --- | --- | --- | --- | --- | --- | --- |
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control |
| |
| Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $385,000 |
Performance Units:(3) | | | | | | | | |
| 2008-2010 Performance Unit Program | --- | --- | --- | --- | $31,808 | $31,808 | $47,713 | $47,713 |
| 2009-2011 Performance Unit Program | --- | --- | --- | --- | $24,552 | $24,552 | $73,656 | $73,656 |
Unvested Stock Options(4) | --- | --- | --- | --- | $16,378 | $16,378(7) | $16,378 | $16,378 |
Medical and Dental Benefits (5) | --- | --- | --- | --- | --- | --- | --- | $15,820 |
| 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. Fisackerly also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009 Pension Benefits." Ifif Mr. Fisackerly's employment were terminated under certain conditions relating to a change in control, heMr. Fisackerly also would also behave been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, which are described in "2009see "2012 Pension Benefits." If Mr. Fisackerly's employment were terminated "forfor cause," he would forfeit his benefit under the System Executive Retirement Plan and other similar supplemental benefits.Plan. | |
2(2) | In the event of a qualifying termination related to a change in control, Mr. Fisackerly would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated atusing the average annual target opportunity.opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $288,950 was assumed. | |
3(3) | In the event of a qualifying termination related to a change in control, Mr. Fisackerly would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, the value of Mr. Fisackerly's awardsFisackerly’s severance payment was calculated as follows:by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $51,000 for the forfeited performance units. 2008 - 2010 Plan – 583 performance units at target, assuming a stock priceIn the event of $81.84
2009 - 2012 Plan – 900 performance units at target, assuming a stock price of $81.84
For scenarios other than a terminationMr. Fisackerly’s death or disability not related to a change in control, the award isMr. Fisackerly would not enhanced or accelerated by the termination event. With respect to death or disability, the award ishave forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Fisackerly’s awards were calculated as follows:
2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75 | |
4(4) | In the event of his death, disability or a change in control, all of Mr. Fisackerly’s unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Fisackerly'sFisackerly’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. Fisackerly exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Fisackerly’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death or disability, Mr. Fisackerly would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month Grant Date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Fisackerly would immediately vest in all unvested restricted stock. |
5(6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. Fisackerly would be eligible to receive Entergy- subsidized medical and dentalCOBRA benefits for a period up to 12 months. | |
6(7) | As of December 31, 2009,2012, compensation and benefits available to Mr. Fisackerly under this scenario are substantially the same as available with a voluntary resignation. | |
7(8) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. |
8 | Under the 2007 Equity Ownership Plan,December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (basedpayable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. | |
| (9) | In December 2010, the assumption that all performance goals were achieved at target).System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. | |
J. Wayne Leonard
Chairman and Chief Executive Officer
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which Entergy's then Chairman and Chief Executive Officer would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (8) | Disability | Death(9) | Change in Control(10) | Termination Related to a Change in Control |
| |
| Annual Incentive Payment(2) | --- | --- | --- | --- | --- | --- | --- | $3,099,600 |
Severance Payment(3) | --- | --- | --- | --- | --- | --- | | $8,495,487 |
Performance Units:(4) | | | | | | | | |
| 2008-2010 Performance Unit Program | --- | --- | --- | $900,240 | $900,240 | $900,240 | $1,350,360 | $1,350,360 |
| 2009-2011 Performance Unit Program | --- | --- | --- | $613,800 | $613,800 | $613,800 | $1,841,400 | $1,841,400 |
Unvested Stock Options(5) | --- | --- | --- | $538,750 | $538,750 | $538,750 (9) | $538,750 | $538,750 |
Unvested Restricted Units(6) | --- | --- | $8,184,000 | --- | $8,184,000 | $8,184,000 | --- | $8,184,000 |
Medical and Dental Benefits(7) | --- | --- | --- | --- | --- | --- | --- | --- |
| 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- |
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(8) | Disability | Death | Change in Control(9) | Termination Related to a Change in Control |
Annual Incentive Payment(2) | --- | --- | --- | --- | --- | --- | --- | $3,240,662 |
Severance Payment(3) | --- | --- | --- | --- | --- | --- | --- | $8,882,116 |
Performance Units:(4) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | $1,104,979 | $1,104,979 | $1,104,979 | --- | $1,243,125 |
| 2012-2014 Performance Unit Program | --- | --- | --- | $571,646 | $571,646 | $571,646 | --- | $1,243,125 |
Unvested Stock Options(5) | --- | --- | --- | $0 | $0 | $0 | --- | $0 |
Unvested Restricted Stock(6) | --- | --- | --- | --- | $491,895 | $491,895 | --- | $1,316,807 |
Medical and Dental Benefits(7) | --- | --- | --- | --- | --- | --- | --- | --- |
280G Tax Gross-up(10) | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. Leonard would have been eligible to retire and entitled to receive his vested pension benefits. However, a termination “for cause” would have resulted in forfeiture of Mr. Leonard’s supplemental retirement benefit. Mr. Leonard is not entitled to additional pension benefits inupon the eventoccurrence of a change in control. For additional information regarding these vested benefits and awards, see “2009“2012 Pension Benefits.” |
2(2) | In the event of a qualifying termination related to a change in control, Mr. Leonard would have been entitled under his retention agreement to receive a lump sum severance payment of his cashequal to Mr. Leonard’s average maximum annual incentive bonus opportunity under the Annual Incentive Plan calculated at maximum annual bonus opportunity.for the Company’s two calendar years immediately preceding the calendar year in which his termination occurs. For purposes of this table, we have calculated the award was calculated at 200% of target opportunity and assumed a base salary of $1,291,500.$1,350,276. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. Leonard would have been entitled to receive pursuant to his retention agreement a lump sum severance payment equal to the sumproduct of 2.99 times the sum of his (a) annual base salary plus (b) his target annual incentive (calculated at 120%Annual Incentive Plan award for any fiscal year (other than the fiscal year in which his date of termination occurs) ending after the effective date of his base salary).retention agreement. |
4(4) | In the event of a qualifying termination related to a change in control, including a termination by Mr. Leonard for good reason, by Entergythe Company other than for cause, disability or death, Mr. Leonard would have forfeited his performance units for all open performance periods and would have been entitled to receive a single sum severance payment pursuant to his retention agreement that would not be based on any outstanding performance periods. The payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the terms ofPerformance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his retention agreement a lump sum payment relating to his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, we have calculated the value of Mr. Leonard’s awards as follows: 2008 - 2010 Plan – 16,500Leonard's severance payment was calculated by taking an average of the target performance units at target, assuming a stockfrom the 2008-2010 Performance Unit Program (16,500 units) and the 2009-2011Performance Unit Program (22,500 units). This average number of units (19,500 units) multiplied by the closing price of $81.84Entergy common stock on December 31, 2012 ($63.75) would equal a severance payment of $1,243,125 for the forfeited performance units.
2009 - 2011 Plan – 22,500 performance units at target, assuming a stock priceIn the event of $81.84
For scenarios other than a terminationMr. Leonard’s death, disability or retirement not related to a change in control, the award isMr. Leonard would not enhanced or accelerated by the termination event. With respect to death or disability, the award ishave forfeited his performance units for all open performance period, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period.
2011 - 2013 Plan – 17,333 (26,000 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 8,967 (26,900 * 12/36) performance units at target, assuming a stock price of $63.75 |
5(5) | In the event of retirement, death, disability, or a qualifying termination related to a change in control, all of Mr. Leonard’s unvested stock options would immediately vest. In addition, Mr. Leonard would be entitled to exercise any outstanding options during a ten-year term extending from the grant date of the options. For purposes of this table, weit was assumed that Mr. Leonard exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2009,2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. Leonard’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
6(6) | Mr. Leonard’s 100,000 restricted units vest in two installments on December 3, 2011 and December 3, 2012. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately inIn the event of a qualifying termination related to a change in control, inall of Mr. Leonard’s unvested restricted stock would immediately vest. In the event of the terminationMr. Leonard’s death or disability, restrictions would lift on a pro-rated portion of his employment byunvested restricted shares that were scheduled to become vested on the immediately following twelve -month grant date anniversary, based on the number of days worked during such twelve-month period. |
| (7) | Upon retirement, Mr. Leonard would be eligible for good reason, byretiree medical and dental benefits, the Companysame as all other than for cause, or by reason of his death or disability. |
7 | retirees. Pursuant to Mr. Leonard’shis retention agreement, in the event of a termination related to a change in control, Mr. Leonard iswould not be eligible to receive additional medical and dentalsubsidized COBRA benefits. Upon retirement Mr. Leonard would be eligible for retiree medical and dental benefits similar to those provided to Entergy retirees. |
8(8) | As of December 31, 2009,2012, Mr. Leonard is retirement eligible and would retire rather than voluntarily resign. Given this scenario, the compensation and benefits available to Mr. Leonard under retirement are substantially the same as available with aupon voluntary resignation. Effective February 1, 2013, Mr. Leonard retired as Chairman and Chief Executive Officer. |
9(9) | Under theThe 2007 Equity Ownership Plan (applicablewas amended in December 2010 so that awards granted after December 30, 2010 require an involuntary termination in order to grants of equity awards made after January 1, 2007), in the event of a plan participant’s death, all unvested stock options would become immediately exercisable. |
10 | Under the 2007 Equity Ownership Plan, plan participants are entitled to receive an acceleration of certain benefits based solelyaccelerate vesting or trigger severance payments upon a change in control in the Company without regardcontrol.
|
| (10) | In December of 2010, Mr. Leonard voluntarily agreed to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:• All unvested stock options would become immediately exercisable; and
• All performance units become vested (based on the assumption that all performance goals were achieved at target).
amend his retention agreement to eliminate excise tax gross up payments. |
Under the terms of Mr. Leonard's retention agreement, weEntergy Corporation may terminate his employment for cause upon Mr. Leonard's:
| · | willful and continued failure to substantially perform his duties (other than because of physical or mental illness or after he has given notice of termination for good reason) that remains uncured for 30 days after receiving a written notice from the Board; or |
| · | willfully engaging in conduct that is demonstrably and materially injurious to us and which results in a conviction of, or entrance of a plea of guilty or nolo contendere (essentially a form of plea in which the accused refuses to contest the charges) to a felony. |
In the event of a change in control, Mr. Leonard maywas entitled to terminate his employment for good reason upon:
| · | the substantial reduction or alteration in the nature or status of his duties or responsibilities; |
| · | a reduction in his annual base salary; |
| · | the relocation of his principal place of employment to a location more than 20 miles from his current place of employment; |
| · | the failure to pay any portion of his compensation within seven days of its due date; |
| · | the failure to continue in effect any compensation plan in which he participates and which iswas material to his total compensation, unless other equitable arrangements arewere made; |
| · | the failure to continue to provide benefits substantially similar to those that he currently enjoysthen enjoyed under any of the pension, savings, life insurance, medical, health and accident or disability plans, or the taking of any other action which materially reducesreduced any of those benefits or deprivesdeprived him of any material fringe benefits that he currently enjoys;then enjoyed; |
| · | the failure to provide him with the number of paid vacation days to which he is entitled in accordance with the normal vacation policy; or |
| · | any purported termination of his employment not taken in accordance with his retention agreement. |
Hugh T. McDonald
President & CEO, Entergy Arkansas
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President & CEO, Entergy Arkansas would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control | |
| | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
| Severance Payment(2) | --- | --- | --- | --- | --- | --- | $483,198 | --- | --- | --- | --- | --- | --- | --- | $505,200 |
Performance Units:(3) | | | | | | | | | | | | | | | |
| 2008-2010 Performance Unit Program | --- | --- | --- | --- | $38,192 | $38,192 | $57,288 | $57,288 | |
| 2009-2011 Performance Unit Program | --- | --- | --- | --- | $24,552 | $24,552 | $73,656 | $73,656 | |
| 2011-2013 Performance Unit Program | | --- | --- | --- | --- | $51,000 | $51,000 | --- | $51,000 |
| 2012-2014 Performance Unit Program | | --- | --- | --- | --- | $31,875 | $31,875 | --- | $51,000 |
Unvested Stock Options(4) | --- | --- | --- | --- | $19,395 | $19,395(7) | $19,395 | $19,395 | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | | --- | --- | --- | --- | $46,601 | $46,601 | --- | $129,338 |
Medical and Dental Benefits (5)(6) | --- | --- | --- | --- | --- | --- | $15,820 | --- | --- | --- | --- | --- | --- | --- | $17,076 |
280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. McDonald also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009 Pension Benefits." Ifif Mr. McDonald's employment were terminated under certain conditions relating to a change in control, heMr. McDonald also would also behave been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, which are described in "2009see "2012 Pension Benefits." If Mr. McDonald's employment were terminated "forfor cause," he would forfeit his Supplementalbenefit under the System Executive Retirement Plan and other similar supplemental benefits.Plan. |
2(2) | In the event of a qualifying termination related to a change in control, Mr. McDonald would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated atusing the average annual target opportunity.opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 50% target opportunity and a base salary of $336,800 was assumed. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. McDonald would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, the value of Mr. McDonald's awards has beenMcDonald’s severance payment was calculated as follows:by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. 2008 - 2010 Plan – 700 performance units at target, assuming a stock priceIn the event of $81.84
2009 - 2011 Plan – 900 performance units at target, assuming a stock price of $81.84
For scenarios other than a terminationMr. McDonald’s death or disability not related to a change in control, the award isMr. McDonald would not enhanced or accelerated by the termination event. With respect to death or disability, the award ishave forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. McDonald’s awards were calculated as follows:
2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75 |
4(4) | In the event of his death, disability or a change in control, all of Mr. McDonald's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. McDonald'sMcDonald’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year extending from the grant date of the options. For purposes of this table, it is assumed that Mr. McDonald exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. McDonald’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
5(5) | In the event of his death or disability, Mr. McDonald would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. McDonald would immediately vest in all unvested restricted stock. |
| (6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. McDonald would be eligible to receive Company- subsidized medical and dentalCOBRA benefits for a period up to 12 months. |
6(7) | As of December 31, 2009,2012, compensation and benefits available to Mr. McDonald under this scenario are substantially the same as available with a voluntary resignation. |
7(8) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. |
8 | Under the 2007 Equity Ownership Plan,December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (basedpayable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying termination in order to accelerate vesting or trigger severance payments. |
| (9) | In December 2010, the assumption that all performance goals were achieved at target).System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
Richard J. SmithWilliam M. Mohl
President & CEO, Entergy Gulf States Louisiana and Chief Operating OfficerEntergy Louisiana
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and Chief Operating OfficerCEO, Entergy Louisiana would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (8) | Termination Related to a Change in Control | | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
| | |
Severance Payment(2) | --- | --- | --- | --- | $3,278,535 | |
Severance Payment(2) | | --- | --- | --- | --- | --- | $1,095,200 |
Performance Units:(3) | | | | | | | | | | | |
| 2008-2010 Performance Unit Program | --- | --- | --- | $212,784 | $319,176 | $319,176 | |
| 2009-2011 Performance Unit Program | --- | --- | --- | $130,944 | $392,832 | $392,832 | |
| 2011-2013 Performance Unit Program | | --- | --- | --- | --- | $106,271 | --- | $108,375 |
| 2012-2014 Performance Unit Program | | --- | --- | --- | --- | $51,000 | --- | $108,375 |
Unvested Stock Options(4) | --- | --- | --- | $150,850 | $150,850 (7) | $150,850 | $150,850 | --- | --- | --- | --- | $0 | --- | $0 |
Unvested Restricted Stock(5) | | --- | --- | --- | --- | $55,208 | --- | $152,169 |
Medical and Dental Benefits(5)(6) | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | $19,063 |
280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, if Mr. SmithMohl's employment were terminated under certain conditions relating to a change in control, Mr. Mohl also would have been eligible to retire and entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, available to Named Executive Officers, see "2009"2012 Pension Benefits." In the event of a termination related to a change in control, pursuant to the terms of the Pension Equalization Plan, Mr. Smith would be eligible for subsidized early retirement even if he does not have company permission to separate from employment. If Mr. Smith'sMohl's employment were terminated for cause, he would not receive aforfeit his benefit under the Pension EqualizationSystem Executive Retirement Plan. |
2(2) | In the event of a qualifying termination related to a change in control, Mr. SmithMohl would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to 2.99the product of two times the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated atusing the average annual target opportunity.opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 60% target opportunity and a base salary of $342,250 was assumed. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. SmithMohl would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his performance units. The payment is calculated as iftermination occurs, assuming all performance goals relating to the performance units were achieved at target level.target. For purposes of the table, the value of Mr. Smith's awards wereMohl’s severance payment was calculated as follows: 2008 - 2010 Plan – 3,900by taking an average of the target performance units at target, assuming a stockfrom the 2008-2010 Performance Unit Program (1,400 units) and the 2009-2011 Performance Unit Program (2,000 units). This average number of units (1,700 units) multiplied by the closing price of $81.84Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $108,375 for the forfeited performance units.
2009 - 2012 Plan – 4,800 performance units at target, assuming a stock priceIn the event of $81.84
With respect toMr. Mohl’s death or disability the award isnot related to a change in control, Mr. Mohl would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on thehis number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Mohl's awards were calculated as follows:
2011 - 2013 Plan – 1,667 (2,500 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 800 (2,400 * 12/36) performance units at target, assuming a stock price of $63.75 |
4(4) | In the event of his death, disability or a change in control, all of Mr. Mohl's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. Smith'sMohl’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for the remainder of the ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. SmithMohl exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Mohl’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death or disability, Mr. Mohl would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Mohl would immediately vest in all unvested restricted stock. |
5(6) | Upon retirement Mr. Smith would be eligible for retiree medical and dental benefits. Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. SmithMohl would not be eligible to receive additionalCompany- subsidized medical and dentalCOBRA benefits similar to those provided to Entergy retirees.for 18 months. |
6(7) | As of December 31, 2009, Mr. Smith is retirement eligible and would retire rather than voluntarily resign. Given that scenario, the2012, compensation and benefits available to Mr. SmithMohl under retirementthis scenario are substantially the same as available with a voluntary resignation. |
7(8) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grants of equity awards made after January 1, 2007), in the event of a plan participant's death, all unvested stock options would become immediately exercisable. |
8 | Under the 2007 Equity Ownership Plan,December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (basedpayable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
| (9) | In December 2010, the assumption that all performance goals were achieved at target)System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
The information in this table does not reflect the agreement entered into with Mr. Smith in December 2009. In order to receive any payments contemplated by the agreement, the planned Spin Transaction must not occur and (i) Mr. Smith must remain employed for 24 months after a public announcement that the Spin Transaction will not occur or (ii) he must remain continuously employed in such capacity for at least six (6) months after any such public announcement and thereafter retire with the consent of Entergy’s Chief Executive Officer. Neither event occurred between the date of this agreement and December 31, 2009. If these events occur, Mr. Smith will be entitled to receive a lump sum cash payment equal to 1.5 times his base salary as of the date of separation from Entergy. See “Compensation Discussion and Analysis” for a complete description of Mr. Smith’s agreement.
Alyson M. Mount
Roderick K. WestSenior Vice President, Chief Accounting Officer
President & CEO, Entergy New Orleans
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Senior Vice President, & CEO, Entergy New OrleansChief Accounting Officer would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2009:2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (6) | Disability | Death (7) | Change in Control (9) | Termination Related to a Change in Control |
| |
| Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $441,000 |
Performance Units:(3) | | | | | | | | |
| 2007-2009 Performance Unit Program | --- | --- | --- | | $38,192 | $38,192 | $57,288 | $57,288 |
| 2008-2010 Performance Unit Program | --- | --- | --- | --- | $24,552 | $24,552 | $73,656 | $73,656 |
Unvested Stock Options(4) | --- | --- | --- | --- | $21,550 | $21,550(7) | $21,550 | $21,550 |
Unvested Restricted Units(8) | --- | --- | $1,227,600 | --- | --- | --- | $1,227,600 | $1,227,600 |
Medical and Dental Benefits(5) | --- | --- | --- | --- | --- | --- | --- | $15,820 |
| 280G Tax Gross-up | --- | --- | --- | --- | --- | --- | --- | $710,829 |
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $756,000 |
Performance Units:(3) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | --- | $56,036 | $56,036 | --- | $78,476 |
| 2012-2014 Performance Unit Program | --- | --- | --- | --- | $43,924 | $43,924 | --- | $78,476 |
Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | --- | --- | --- | --- | $46,474 | $46,474 | --- | $133,388 |
Medical and Dental Benefits(6) | --- | --- | --- | --- | --- | --- | --- | $8,518 |
280G Tax Gross-up(9) | --- | --- | --- | --- | --- | --- | --- | --- |
1(1) | In addition to the payments and benefits in the table, Mr. West also would have been entitled to receive his vested pension benefits. For a description of the pension benefits available to Named Executive Officers, see "2009 Pension Benefits." If Mr. West'sif Ms. Mount's employment were terminated under certain conditions relating to a change in control, heMs. Mount also would also behave been entitled to receive her vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, which are described in "2009see "2012 Pension Benefits." If Mr. West'sMs. Mount's employment were terminated "forfor cause," he she would forfeit hisher benefit under the System Executive Retirement Plan and other similar supplemental benefits.Plan. |
2(2) | In the event of a qualifying termination related to a change in control, Mr. WestMs. Mount would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to one time histhe product of 2.00 times the sum of (a) her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) her annual incentive, calculated atusing the average annual target opportunity.opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 35% target opportunity and a base salary of $280,000 was assumed. |
3(3) | In the event of a qualifying termination related to a change in control, Mr. WestMs. Mount would have forfeited her performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the System Executive Continuity Planequity ownership plans, a lump sumsingle-sum severance payment relatingthat would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to histhe 2011 Equity Ownership Plan. For both the 2011-2013 performance units. Theperiod and the 2012-2014 performance period, the payment iswould have been calculated as ifusing the average annual number of performance units she would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which her termination occurs, assuming all performance goals relating to the performance unit were achieved at target level.target. For purposes of the table, the value of Mr. West's awards have beenMs. Mount’s severance payment was calculated as follows: 2008 - 2010 Plan – 700by taking an average of the target performance units at target, assuming a stockfrom the 2008-2010 Performance Unit Program (739 units) and the 2009-2011 Performance Unit Program (1,722 units). This average number of units (1,231 units) multiplied by the closing price of $81.84
2009 -Entergy stock on December 31, 2012 Plan – 900($63.75) would equal a severance payment of $78,476 for the forfeited performance units at target, assuming a stock price of $81.84units.
For scenarios other than a terminationIn the event of Ms. Mount’s death or disability not related to a change in control, the award isMs. Mount would not enhanced or accelerated by the termination event. With respect to death or disability, the award ishave forfeited her performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on theher number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Ms. Mount's awards were calculated as follows:
2011 - 2013 Plan – 879 (1,319 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 689 (2,067 *12/36) performance units at target, assuming a stock price of $63.75 |
4(4) | In the event of death, disability or a change in control, all of Ms. Mount's unvested stock options granted prior to December 30, 2010 would immediately vest In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Mount’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, she would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it was assumed that Ms. Mount exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Ms. Mount’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of her death or disability, Ms. Mount would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of her death or Disability. In the event of her qualifying termination related to a change in control, Ms. Mount would immediately vest in all unvested restricted stock. |
| (6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Mount would be eligible to receive Company- subsidized COBRA benefits for 18 months. |
| (7) | As of December 31, 2012, compensation and benefits available to Ms. Mount under this scenario are substantially the same as available with a voluntary resignation. |
| (8) | With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: ·All unvested stock options would become immediately exercisable; and ·Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
| (9) | In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
Sallie T. Rainer
President & CEO, Entergy Texas
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President & CEO, Entergy Texas would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $357,500 |
Performance Units:(3) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | --- | $26,903 | $26,903 | --- | $36,465 |
| 2012-2014 Performance Unit Program | --- | --- | --- | --- | $27,476 | $27,476 | --- | $36,465 |
Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | --- | --- | --- | --- | $37,931 | $37,931 | --- | $110,628 |
Medical and Dental Benefits(6) | --- | --- | --- | --- | --- | --- | --- | $17,076 |
280G Tax Gross-up(9) | --- | --- | --- | --- | --- | --- | --- | --- |
| (1) | In addition to the payments and benefits in the table, if Ms. Rainer's employment were terminated under certain conditions relating to a change in control, Ms. Rainer also would have been entitled to receive her vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2012 Pension Benefits." If Ms. Rainer's employment were terminated for cause, she would forfeit her benefit under the System Executive Retirement Plan. |
| (2) | In the event of a qualifying termination related to a change in control, Ms. Rainer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 1.00 times the sum of (a) her annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) her annual incentive, calculated using the average annual target opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 30% target opportunity and a base salary of $275,000 was assumed. |
| (3) | In the event of a qualifying termination related to a change in control, Ms. Rainer would have forfeited her performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units she would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which her termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Ms. Rainer’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (369 units) and the 2009-2011 Performance Unit Program (775 units). This average number of units (572 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $36,465 for the forfeited performance units. In the event of Ms. Rainer’s death or disability not related to a change in control, Ms. Rainer would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on her number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Ms. Rainer's awards were calculated as follows: 2011 - 2013 Plan – 422 (633 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 431 (1,292 * 12/36) performance units at target, assuming a stock price of $63.75 |
| (4) | In the event of death, disability or a change in control, all of Ms. Rainer's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of her death, disability or qualifying termination related to a change in control, all of Ms. Rainer’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it was assumed that Ms. Rainer exercised her options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Ms. Rainer’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death or disability, Ms. Rainer would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of her death or Disability. In the event of her qualifying termination related to a change in control, Ms. Rainer would immediately vest in all unvested restricted stock. |
| (6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Ms. Rainer would be eligible to receive Company- subsidized COBRA benefits for 12 months. |
| (7) | As of December 31, 2012, compensation and benefits available to Ms. Rainer under this scenario are substantially the same as available with a voluntary resignation. |
| (8) | With respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows: ·All unvested stock options would become immediately exercisable; and ·Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
| (9) | In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
Charles L. Rice, Jr.
President & CEO, Entergy New Orleans
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the President and CEO, Entergy New Orleans would have been entitled to receive as a result of a termination of his employment under various scenarios as of December 31, 2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(7) | Disability | Death | Change in Control(8) | Termination Related to a Change in Control |
Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $352,940 |
Performance Units:(3) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | --- | $51,000 | $51,000 | --- | $51,000 |
| 2012-2014 Performance Unit Program | --- | --- | --- | --- | $31,875 | $31,875 | --- | $51,000 |
Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | --- | --- | --- | --- | $36,019 | $36,019 | --- | $100,905 |
Medical and Dental Benefits(6) | --- | --- | --- | --- | --- | --- | --- | $900 |
280G Tax Gross-up(9) | --- | --- | --- | --- | --- | --- | --- | --- |
| (1) | In addition to the payments and benefits in the table, if Mr. Rice's employment were terminated under certain conditions relating to a change in control, Mr. Rice also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2012 Pension Benefits." If Mr. Rice's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan. |
| (2) | In the event of a qualifying termination related to a change in control, Mr. Rice would be entitled to receive pursuant to the System Executive Continuity Plan, a lump sum severance payment equal to the product of one time the sum of (a) his annual base salary as is effect at any time within one year prior to the commencement of a of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 40% target opportunity and a base salary of $252,100 was assumed. |
| (3) | In the event of a qualifying termination related to a change in control, Mr. Rice would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Rice’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (700 units) and the 2009-2011 Performance Unit Program (900 units). This average number of units (800 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $ $51,000 for the forfeited performance units. In the event of Mr. Rice’s death or disability not related to a change in control, Mr. Rice would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. Rice’s awards were calculated as follows: 2011 - 2013 Plan – 800 (1,200 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 500 (1,500 * 12/36) performance units at target, assuming a stock price of $63.75 |
| (4) | In the event of his death, disability or a change in control, all of Mr. Rice's unvested stock options granted prior to December 30, 2010 would immediately vest. In the event of his death, disability or qualifying termination related to a change in control, all of Mr. West'sRice’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise his stock options for athe remainder of the ten-year term extending from the grant date of the options. For purposes of this table, it is assumed that Mr. WestRice exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 31, 2009,2012, and the applicable exercise price of each option share. As of December 31, 2012, the closing stock price for of Mr. Rice’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death or disability, Mr. Rice would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. Rice would immediately vest in all unvested restricted stock. |
5(6) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. WestRice would be eligible to receive Company- subsidized medical and dentalCOBRA benefits for period up to 12 months. |
6(7) | As of December 31, 2009,2012, compensation and benefits available to Mr. WestRice under this scenario are substantially the same as available with a voluntary resignation. |
7(8) | UnderWith respect to grants made under the 2007 Equity Ownership Plan (applicableprior to grantsDecember 30, 2010, plan participants are entitled to receive an acceleration of equity awards made after January 1, 2007),certain benefits based solely upon a change in control of the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a plan participant's death, allchange in control are as follows: ·All unvested stock options would become immediately exercisable.exercisable; and ·Severance benefits in place of performance units become payable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted on or after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
8(9) | In December 2010, the System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
Roderick K. West
Executive Vice President & Chief Administrative Officer
The following table shows certain payments and benefits, excluding vested or earned awards and benefits, which the Executive Vice President & Chief Administrative Officer would have been entitled to receive as a result of a termination of her employment under various scenarios as of December 31, 2012:
Benefits and Payments Upon Termination(1) | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement(8) | Disability | Death | Change in Control(9) | Termination Related to a Change in Control |
Severance Payment(2) | --- | --- | --- | --- | --- | --- | --- | $2,994,700 |
Performance Units:(3) | | | | | | | | |
| 2011-2013 Performance Unit Program | --- | --- | --- | --- | $250,729 | $250,729 | --- | $277,313 |
| 2012-2014 Performance Unit Program | --- | --- | --- | --- | $114,750 | $114,750 | --- | $277,313 |
Unvested Stock Options(4) | --- | --- | --- | --- | $0 | $0 | --- | $0 |
Unvested Restricted Stock(5) | --- | --- | --- | --- | $148,601 | $148,601 | --- | $408,786 |
Unvested Restricted Units(6) | --- | --- | $956,250 | --- | --- | --- | $956,250 | $956,250 |
Medical and Dental Benefits(7) | --- | --- | --- | --- | --- | --- | --- | $25,614 |
280G Tax Gross-up(10) | --- | --- | --- | --- | --- | --- | --- | --- |
| (1) | In addition to the payments and benefits in the table, if Mr. West's employment were terminated under certain conditions relating to a change in control, Mr. West also would have been entitled to receive his vested pension benefits and would have been eligible for early retirement benefits. For a description of the pension benefits, see "2012 Pension Benefits." If Mr. West's employment were terminated for cause, he would forfeit his benefit under the System Executive Retirement Plan. |
| (2) | In the event of a qualifying termination related to a change in control, Mr. West would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to the product of 2.99 times the sum of (a) his annual base salary as in effect at any time within one year prior to the commencement of a change in control period or, if higher, immediately prior to a circumstance constituting good reason plus (b) his annual incentive, calculated using the average annual target opportunity under the Annual Incentive Plan for the two calendar years immediately preceding the calendar year in which the participant’s termination occurs. For purposes of this table, a 70% target opportunity and a base salary of $589,160 was assumed. |
| (3) | In the event of a qualifying termination related to a change in control, Mr. West would have forfeited his performance units for the 2011-2013 performance period and would have been entitled to receive, pursuant to the equity ownership plans, a single-sum severance payment that would not be based on any outstanding performance periods. This is also applicable for the 2012-2014 performance period pursuant to the 2011 Equity Ownership Plan. For both the 2011-2013 performance period and the 2012-2014 performance period, the payment would have been calculated using the average annual number of performance units he would have been entitled to receive under the Performance Unit Program with respect to the two most recent performance periods preceding the calendar year in which his termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. West’s severance payment was calculated by taking an average of the target performance units from the 2008-2010 Performance Unit Program (3,900 units) and the 2009-2011 Performance Unit Program (4,800 units). This average number of units (4,350 units) multiplied by the closing price of Entergy stock on December 31, 2012 ($63.75) would equal a severance payment of $277,313 for the forfeited performance units. In the event of Mr. West’s death or disability not related to a change in control, Mr. West would not have forfeited his performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his number of months of participation in each open Performance Unit Program performance cycle. The amount of the award is based on actual performance achieved, with a stock price set as of the end of the performance period, and payable in the form of a lump sum after the completion of the performance period. For purposes of the table, the value of Mr. West's awards were calculated as follows: 2011 - 2013 Plan – 3,933 (5,900 * 24/36) performance units at target, assuming a stock price of $63.75 2012 - 2014 Plan – 1,800 (5,400 *12/36) performance units at target, assuming a stock price of $63.75 |
| (4) | In the event of death, disability or a change in control, all of Mr. West's unvested stock options granted prior to December 30, 2010 would immediately vest In the event of his death, disability or qualifying termination related to a change in control, all of Mr. West’s unvested stock options granted on or after December 30, 2010 would immediately vest. In addition, he would be entitled to exercise any unexercised options during a ten-year term extending from the grant date of the options. For purposes of this table, it was assumed that Mr. West exercised his options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2012, and the exercise price of each option share. As of December 31, 2012, the closing stock price for Mr. West’s unvested options fell below the exercise prices and accordingly considered “underwater” and are excluded from the table. |
| (5) | In the event of his death or disability, Mr. West would immediately vest in a pro-rated portion of the unvested restricted stock that was otherwise scheduled to become vested on the immediately following twelve (12)-month grant date anniversary date (as well as dividends declared on the pro-rated portion of such restricted stock). The pro-rated vested portion would be determined based on the number of days between the most recent preceding twelve (12)-month grant date anniversary date and the date of his death or Disability. In the event of his qualifying termination related to a change in control, Mr. West would immediately vest in all unvested restricted stock. |
| (6) | Mr. West's 15,000 restricted unit vest 100% in 2013. Pursuant to his restricted unit agreement, any unvested restricted units will vest immediately in the event of termination for good reason or not for cause and a change in control. |
9(7) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr. West would be eligible to receive Company- subsidized COBRA benefits for 18 months. |
| (8) | As of December 31, 2012, compensation and benefits available to Mr. West under this scenario are substantially the same as available with a voluntary resignation. |
| (9) | UnderWith respect to grants made under the 2007 Equity Ownership Plan prior to December 30, 2010, plan participants are entitled to receive an acceleration of certain benefits based solely upon a change in control inof the Company and without regard to whether their employment is terminated as a result of a change in control. The accelerated benefits in the event of a change in control are as follows:
· All unvested stock options would become immediately exercisable.exercisable; and · AllSeverance benefits in place of performance units become vested (based onpayable as described in footnote 3 above. The 2007 Equity Ownership Plan was amended in December 2010 so that awards granted after December 30, 2010 require a qualifying involuntary termination in order to accelerate vesting or trigger severance payments. |
| (10) | In December 2010, the assumption that all performance goals were achieved at target).System Executive Continuity Plan was amended to eliminate excise tax gross-up payments. |
In the following sections, additional information is provided regarding certain of the scenarios described in the tables above:
Termination Related to a Change in Control
Under the System Executive Continuity Plan, the Named Executive Officers will be entitled to the benefits described in the tables above in the event of a termination related to a change in control if their employment is terminated other than for cause or if they terminate their employment for good reason, in each case within a period commencing 90 days prior to and ending 24 months following a change in control.
A change in control includes the following events:
| · | The purchase of 25%30% or more of either the common stock or the combined voting power of the voting securities, the merger or consolidation of Entergy Corporation (unless Entergy Corporation's board members constitute at least a majority of the board members of the surviving entity);securities; |
| · | the merger or consolidation of Entergy Corporation (unless Entergy Corporation's board members constitute at least a majority of the board members of the surviving entity;entity); |
| · | the liquidation, dissolution or sale of all or substantially all of Entergy Corporation's assets; or |
| · | a change in the composition of Entergy Corporation's board such that, during any two-year period, the individuals serving at the beginning of the period no longer constitute a majority of Entergy Corporation's board at the end of the period. |
The proposed separation of the non-utility nuclear business in a tax-free spin-off to Entergy Corporation's shareholders does not constitute a "Change in Control" for purposes of the System Executive Continuity Plan.
Entergy Corporation may terminate a Named Executive Officer's employment for cause under the System Executive Continuity Plan if he or she:
| · | fails to substantially perform his or her duties for a period of 30 days after receiving notice from the board;Board; |
| · | engages in conduct that is injurious to Entergy Corporation or any of its subsidiaries; |
| · | is convicted or pleads guilty to a felony or other crime that materially and adversely affects his or her ability to perform his or her duties or Entergy Corporation's reputation; |
| · | violates any agreement with Entergy Corporation or any of its subsidiaries; or |
| · | discloses any of Entergy Corporation's confidential information without authorization. |
A Named Executive Officer may terminate employment with Entergy Corporation for good reason under the System Executive Continuity Plan if, without the Named Executive Officer's consent:
| · | the nature or status of his or her duties and responsibilities is substantially altered or reduced compared to the period prior to the change in control; |
| · | his or her salary is reduced by 5% or more; |
| · | he or she is required to be based outside of the continental United States at somewhere other than the primary work location prior to the change in control; |
| · | any of his or her compensation plans are discontinued without an equitable replacement; |
| · | his or her benefits or number of vacation days are substantially reduced; or |
| · | his or her employment is purported to be terminated other than in accordance with the System Executive Continuity Plan. |
In addition to participation in the System Executive Continuity Plan, upon the completion of a transaction resulting in a change in control of Entergy Corporation, benefits already accrued under the System Executive Retirement Plan and Pension Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason. Any awards granted under the Equity Ownership Planequity ownership plans will become fully vested upon a Change in Control without regard to whetherand the executive is involuntarily terminated without cause or terminates employment for good reason. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.
Under certain circumstances, the payments and benefits received by a Named Executive Officer pursuant to the System Executive Continuity Plan may be forfeited and, in certain cases, subject to repayment. Benefits are no longer payable under the System Executive Continuity Plan, and unvested performance units under the Performance Unit Program are subject to forfeiture, if the executive:
| · | accepts employment with Entergy Corporation or any of its subsidiaries; |
| · | elects to receive the benefits of another severance or separation program; |
| · | removes, copies or fails to return any property belonging to Entergy Corporation or any of its subsidiaries; |
| · | discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries; or |
| · | violates their non-competition provision, which generally runs for two years but extends to three years if permissible under applicable law. |
Furthermore, if the executive discloses non-public data or information concerning Entergy Corporation or any of its subsidiaries or violates their non-competition provision, he or she will be required to repay any benefits previously received under the System Executive Continuity Plan.
Termination for Cause
If a Named Executive Officer's employment is terminated for "cause" (as defined in the System Executive Continuity Plans and described above under "Termination Related to a Change in Control"), he or she is generally entitled to the same compensation and separation benefits described below under "Voluntary Resignation."Resignation" except that all options may no longer be exercisable.
Voluntary Resignation
If a Named Executive Officer voluntarily resigns from an Entergy System company employer, he or she is entitled to all accrued benefits and compensation as of the separation date, including qualified pension benefits (if any) and other post-employment benefits on terms consistent with those generally available to other salaried employees. In the case of voluntary resignation, the officer would forfeit all unvested stock options, shares of restricted stock and restricted units as well as any perquisites to which he or she is entitled as an officer. In addition, the officer would forfeit, except as described below, his or her right to receive incentive payments under the Performance Unit Program or the ExecutiveAnnual Incentive Plan. If the officer resigns after the completion of an ExecutiveAnnual Incentive Plan or Performance Unit Program performance period, he or she could receive a payout under the Performance Unit Program based on the outcome of the performance cycle and could, at the Entergy Corporation's discretion, receive an annual incentive payment under the ExecutiveAnnual Incentive Plan. Any vested stock options held by the officer as of the separation date will expire the earlier of ten years from date of grant or 90 days from the last day of active employment.
Retirement
Under Entergy Corporation's retirement plans, a Named Executive Officer's eligibility for retirement benefits is based on a combination of age and years of service. Normal retirement is defined as age 65. Early retirement is defined under the qualified retirement plan as minimum age 55 with 10 years of service and in the case of the System Executive Retirement Plan and the supplemental credited service under the Pension Equalization Plan, the consent of Entergy System company employer.
Upon a Named Executive Officer's retirement, he or she is generally entitled to all accrued benefits and compensation as of the separation date, including qualified pension benefits and other post-employment benefits consistent with those generally available to salaried employees. The annual incentive payment under the ExecutiveAnnual Incentive Plan is pro-rated based on the actual number of days employed during the performance year in which the retirement date occurs. Similarly, payments under the Performance Unit Program for those retiring with a minimum 12 months of participation are pro-rated based on the actual numberfull months of days employed,participation, in each outstanding performance cycle, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle, consistent with the timing of payments to active participants in the ExecutiveAnnual Incentive Plan and the Performance Unit Program, respectively.
Unvested stock options issued under the Equity Ownership Planequity ownership plans vest on the retirement date and expire ten years from the grant date of the options. Any restricted stock units held (other than those issued under the Performance Unit Program) by the executive upon his or her retirement are forfeited, and perquisites (other than short-term financial counseling services) are not available following the separation date.
Disability
If a Named Executive Officer's employment is terminated due to disability, he or she generally is entitled to the same compensation and separation benefits described above under "Retirement," except that restricted units may be subject to specific disability benefits (as noted, where applicable, in the tables above).
Death
If a Named Executive Officer dies while actively employed by an Entergy System company employer, he or she generally is entitled to the same compensation and separation benefits described above under "Retirement," except that:including:
| · | all unvested stock options granted prior to January 1, 2007 are forfeited;will vest immediately; |
| · | vested stock options will expire the earlier of ten years from the grant date or three years following the executive's death;date; and |
| · | restricted units may be subject to specific death benefits depending on the restricted stock unit agreement (as noted, where applicable, in the tables above). |
Compensation of Directors
For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading "Director Compensation"“Director Compensation”, which information is incorporated herein by reference. The Boards of Directors of Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are comprised solely of employee directors who receive no compensation for service as directors.
Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans and Entergy Texas. The information with respect to persons known by Entergy Corporation to be beneficial owners of more than 5% of Entergy Corporation'sCorporation’s outstanding common stock is included under the heading "Stockholders“Stockholders Who Own at Least Five Percent"Percent” in the Proxy Statement, which information is incorporated herein by reference. The registrants know of no contractual arrangements that may, at a subsequent date, result in a change in control of any of the registrants.
The following table sets forth the beneficial ownership of Common Stock of Entergy Corporation and stock-based units as of DecemberJanuary 31, 20092013 for all directors and Named Executive Officers. Unless otherwise noted, each person had sole voting and investment power over the number of shares of Common Stock and stock-based units of Entergy Corporation set forth across from his or her name.
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| | | | | | | | | | | | | |
| Entergy Corporation | | | | | | | | | | | | |
| Maureen S. Bateman* | | 6,700 | | - | | 7,200 | | 4,943 | | - | | 9,600 |
| W. Frank Blount* | | 12,234 | | - | | 17,600 | |
| Leo P. Denault** | | 7,543 | | 276,619 | | - | | 26,725 | | 351,662 | | - |
| Gary W. Edwards* | | 800 | | - | | 4,831 | | 1,627 | | - | | 7,874 |
| Alexis Herman* | | 3,900 | | - | | 4,800 | | 5,777 | | - | | 7,200 |
| Donald C. Hintz* | | 7,755 | | 260,000 | | 5,200 | | 9,558 | | 20,000 | | 7,493 |
| J. Wayne Leonard*** | | 257,875 | | 1,864,733 | | 2,842 | | 348,273 | | 1,361,533 | | 3,271 |
| Stuart L. Levenick* | | 2,600 | | - | | 3,031 | | 4,443 | | - | | 5,431 |
| Blanche L. Lincoln* | | | 1,132 | | - | | 1,000 |
| Stewart C. Myers* | | 138 | | - | | - | | 2,101 | | - | | 2,183 |
James R. Nichols* (3) | | 9,894 | | - | | 18,626 | |
| William A. Percy, II* | | 2,650 | | - | | 10,754 | | 3,743 | | - | | 13,904 |
| Mark T. Savoff** | | 831 | | 144,800 | | 240 | | 11,590 | | 189,333 | | 277 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - | | 58,657 | | 341,600 | | - |
| W. J. Tauzin* | | 2,500 | | - | | 2,893 | | 4,343 | | - | | 5,293 |
| Gary J. Taylor** | | 1,394 | | 279,833 | | - | |
| Roderick K. West** | | | 13,813 | | 55,334 | | - |
| Steven V. Wilkinson* | | 3,655 | | - | | 4,427 | | 5,498 | | - | | 6,827 |
| All directors and executive | | | | | | | | | | | | |
| officers as a group (21 persons) | | 354,139 | | 3,831,922 | | 82,444 | |
| officers as a group (20 persons) | | | 551,535 | | 2,617,812 | | 70,353 |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| | | | | | | |
| Entergy Arkansas | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| Hugh T. McDonald*** | | 13,042 | | 49,066 | | - |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 462,755 | | 2,305,278 | | 3,548 |
| Entergy Gulf States Louisiana | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| William M. Mohl*** | | 6,292 | | 43,833 | | - |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 456,005 | | 2,300,045 | | 3,548 |
| | | | | | | |
| Entergy Louisiana | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| William M. Mohl*** | | 6,292 | | 43,833 | | - |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 456,005 | | 2,300,045 | | 3,548 |
| | | | | | | |
| Entergy Mississippi | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| Haley R. Fisackerly*** | | 4,714 | | 24,766 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 447,260 | | 2,197,845 | | 3,548 |
| | | | | | | |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| | | | | | | |
| Entergy Arkansas | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| Leo P. Denault*** | | 7,543 | | 276,619 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Hugh T. McDonald*** | | 8,304 | | 70,189 | | - |
| Mark T. Savoff* | | 831 | | 144,800 | | 240 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| All directors and executive | | | | | | |
| officers as a group (11 persons) | | 309,617 | | 3,642,111 | | 3,082 |
| | | | | | | |
| Entergy Gulf States Louisiana | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| E. Renae Conley*** | | 12,388 | | 60,317 | | - |
| Leo P. Denault*** | | 7,543 | | 276,619 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Mark T. Savoff* | | 831 | | 144,800 | | 240 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| All directors and executive | | | | | | |
| officers as a group (11 persons) | | 313,701 | | 3,632,239 | | 3,082 |
| | | | | | | |
| Entergy Louisiana | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| E. Renae Conley*** | | 12,388 | | 60,317 | | - |
| Leo P. Denault*** | | 7,543 | | 276,619 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Mark T. Savoff* | | 831 | | 144,800 | | 240 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| All directors and executive | | | | | | |
| officers as a group (11 persons) | | 313,701 | | 3,632,239 | | 3,082 |
| | | | | | | |
| Entergy Mississippi | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| Leo P. Denault*** | | 7,543 | | 276,619 | | - |
| Haley R. Fisackerly*** | | 1,645 | | 8,100 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Mark T. Savoff* | | 831 | | 144,800 | | 240 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| All directors and executive | | | | | | |
| officers as a group (11 persons) | | 302,958 | | 3,580,022 | | 3,082 |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| | | | | | | |
| Entergy New Orleans | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| Leo P. Denault** | | 7,543 | | 276,619 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| Roderick K. West*** | | 1,607 | | 21,001 | | - |
| Sherri Winslow* | | 198 | | 4,167 | | - |
| All directors and executive | | | | | | |
| officers as a group (12 persons) | | 303,118 | | 3,597,090 | | 3,082 |
| | | | | | | |
| Entergy Texas | | | | | | |
| Theodore H. Bunting, Jr.** | | 658 | | 34,200 | | - |
| Leo P. Denault*** | | 7,543 | | 276,619 | | - |
| Joseph F. Domino*** | | 4,652 | | 56,167 | | - |
| J. Wayne Leonard** | | 257,875 | | 1,864,733 | | 2,842 |
| Mark T. Savoff* | | 831 | | 144,800 | | 240 |
| Richard J. Smith** | | 29,381 | | 415,668 | | - |
| Gary J. Taylor* | | 1,394 | | 279,833 | | - |
| All directors and executive | | | | | | |
| officers as a group (11 persons) | | 305,965 | | 3,628,089 | | 3,082 |
| | | | | | | |
Name | | Shares (1) | | Options Exercisable Within 60 Days | | Stock Units (2) |
| Entergy New Orleans | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Charles L. Rice, Jr.*** | | 3,473 | | 3,466 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 446,019 | | 2,176,545 | | 3,548 |
| | | | | | | |
| Entergy Texas | | | | | | |
| Theodore H. Bunting, Jr.*** | | 9,607 | | 70,233 | | - |
| Leo P. Denault*** | | 26,725 | | 351,662 | | - |
| Joseph F. Domino** | | 2,650 | | 59,966 | | - |
| J. Wayne Leonard** | | 348,273 | | 1,361,533 | | 3,271 |
| Alyson M. Mount** | | 5,507 | | 31,400 | | - |
| Sallie T. Rainer*** | | 5,077 | | 14,900 | | - |
| Mark T. Savoff* | | 11,590 | | 189,333 | | 277 |
| Roderick K. West** | | 13,813 | | 55,334 | | - |
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 450,273 | | 2,247,945 | | 3,548 |
| * | Director of the respective Company |
| ** | Named Executive Officer of the respective Company |
| *** | Director and Named Executive Officer of the respective Company |
| (1) | The number of shares of Entergy Corporation common stock owned by each individual and by all directors and executive officers as a group does not exceed one percent of the outstanding Entergy Corporation common stock. |
| (2) | Represents the balances of phantom units each executive holds under the defined contribution restoration plan and the deferral provisions of the Equity Ownership Plan. These units will be paid out in either Entergy Corporation Common Stock or cash equivalent to the value of one share of Entergy Corporation Common Stockcommon stock per unit on the date of payout, including accrued dividends. The deferral period is determined by the individual and is at least two years from the award of the bonus. For directors of Entergy Corporation the phantom units are issued under the Service Recognition Program for Outside Directors. All non-employee directors are credited with units for each year of service on the Board. In addition, Messrs. Edwards, Hintz and Percy are deferringhave deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in unitscash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period. |
(3) | Excludes 4,059 shares that are owned by a charitable foundation that Mr. Nichols controls. |
| |
Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2009.2012. Information is included for equity compensation plans approved by the stockholders and equity compensation plans not approved by the stockholders.
Plan | | Number of Securities to be Issued Upon Exercise of Outstanding Options (a) | | Weighted Average Exercise Price (b) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a)) (c) | | Number of Securities to be Issued Upon Exercise of Outstanding Options (a) | | Weighted Average Exercise Price (b) | | Number of Securities Remaining Available for Future Issuance (excluding securities reflected in column (a)) (c) |
| | | | | | | | | | | | | |
Equity compensation plans approved by security holders (1) | | 9,665,002 | | $74.68 | | 3,276,876 | | 9,413,476 | | $80.32 | | 6,081,969 |
Equity compensation plans not approved by security holders(2) | | 1,656,069 | | $40.22 | | - | | 144,870 | | $44.45 | | - |
| Total | | 11,321,071 | | $69.64 | | 3,276,876 | | 9,558,346 | | $79.77 | | 6,081,969 |
| (1) | Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998.1998, the 2007 Equity Ownership Plan and the 2011 Equity Ownership Plan. The 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries ("2007 Plan"), was approved by Entergy Corporation shareholders on May 12, 2006.2006, and 7,000,000 shares of Entergy Corporation common stock can be issued, with no more than 2,000,000 shares available for non-option grants. The 2011 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 6, 2011, and 5,500,000 shares of Entergy Corporation common stock can be issued from the 20072011 Equity Ownership Plan, with no more than 2,000,000 shares available for non-optionincentive stock option grants. The Equity Ownership Plan, the 2007 Equity Ownership Plan and the 20072011 Equity Ownership Plan (the "Plans"“Plans”) are administered by the Personnel Committee of the Board of Directors (other than with respect to awards granted to non-employee directors, which awards are administered by the entire Board of Directors). Eligibility under the Plans is limited to the non-employee directors and to the officers and employees of an Entergy System employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by the Company.Entergy Corporation. The Plans provide for the issuance of stock options, restricted shares, equity awards (units whose value is related to the value of shares of the Common Stock but do not represent actual shares of Common Stock), performance awards (performance shares or units valued by reference to shares of Common Stock or performance units valued by reference to financial measures or property other than Common Stock) and other stock-based awards. |
| (2) | Entergy has a Board-approved stock-based compensation plan. However, effective May 9, 2003, the Board has directed that no further awards be issued under that plan. |
For information regarding certain relationships, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings "Corporate“Corporate Governance - Director Independence"Independence” and "Transactions“Transactions with Related Persons,"” which information is incorporated herein by reference.
Since December 31, 2007,2011, none of the Subsidiaries or any of their affiliates has participated in any transaction involving an amount in excess of $120,000 in which any director or executive officer of any of the Subsidiaries, any nominee for director, or any immediate family member of the foregoing had a material interest as contemplated by Item 404(a) of Regulation S-K ("(“Related Party Transactions"Transactions”).
Entergy Corporation'sCorporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of Related Party Transactions. Under these policies and procedures, the Corporate Governance Committee, or a subcommittee of the Board of Directors of Entergy Corporation comprisedcomposed of independent directors, reviews the transaction and either approves or rejects the transaction after taking into account the following factors:
| · | Whether the proposed transaction is on terms at least as favorable to Entergy Corporation or the subsidiary as those achievable with an unaffiliated third party; |
| · | Size of transaction and amount of consideration; |
| · | Nature of the interest; |
| · | Whether the transaction involves a conflict of interest; |
| · | Whether the transaction involves services available from unaffiliated third parties; and |
| · | Any other factors that the Corporate Governance Committee or subcommittee deems relevant. |
The policy does not apply to (a) compensation and Related Party Transactions involving a director or an executive officer solely resulting from that person'sperson’s service as a director or employment with the Company so long as the compensation is reported in the Company's filings with the SEC,approved by Entergy’s Board of Directors, (b) transactions involving the rendering of services as a public utility at rates or charges fixed in conformity with law or governmental authority or (c) any other categories of transactions currently or in the future excluded from the reporting requirements of Item 404(a) of Regulation SK.
None of the Subsidiaries are listed issuers. As previously noted, the Boards of Directors of the Subsidiaries are comprisedcomposed solely of employee directors. None of the Boards of Directors of any of the Subsidiaries has any committees.
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 20092012 and 20082011 by Deloitte & Touche LLP the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, "Deloitte & Touche"), which includes Deloitte Consulting were as follows:
| | | 2009 | | 2008 | | 2012 | | 2011 |
| Entergy Corporation (consolidated) | | | | | | | | |
| Audit Fees | | $9,175,534 | | $10,587,151 | | $11,162,397 | | $9,096,870 |
| Audit-Related Fees (a) | | 892,150 | | 778,689 | | 540,000 | | 740,000 |
| | | | | | | | | |
| Total audit and audit-related fees | | 10,067,684 | | 11,365,840 | | 11,702,397 | | 9,836,870 |
| Tax Fees (b) | | - | | - | | - | | 46,083 |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $10,067,684 | | $11,365,840 | | $11,702,397 | | $9,882,953 |
| | | | | | | | | |
| Entergy Arkansas | | | | | | | | |
| Audit Fees | | $924,277 | | $885,674 | | $992,666 | | $969,218 |
| Audit-Related Fees (a) | | - | | - | | - | | - |
| | | | | | | | | |
| Total audit and audit-related fees | | 924,277 | | 885,674 | | 992,666 | | 969,218 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $924,277 | | $885,674 | | $992,666 | | $969,218 |
| | | | | | | | | |
| Entergy Gulf States Louisiana | | | | | | | | |
| Audit Fees | | $871,277 | | $1,232,594 | | $905,666 | | $897,218 |
| Audit-Related Fees (a) | | 95,000 | | 200,000 | | 80,000 | | 80,000 |
| | | | | | | | | |
| Total audit and audit-related fees | | 966,277 | | 1,432,594 | | 985,666 | | 977,218 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $966,277 | | $1,432,594 | | $985,666 | | $977,218 |
| | | | | | | | | |
| Entergy Louisiana | | | | | | | | |
| Audit Fees | | $881,277 | | $1,091,094 | | $1,032,666 | | $1,031,718 |
| Audit-Related Fees (a) | | 95,000 | | 190,000 | | 80,000 | | 280,000 |
| | | | | | | | | |
| Total audit and audit-related fees | | 976,277 | | 1,281,094 | | 1,112,666 | | 1,311,718 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $976,277 | | $1,281,094 | | $1,112,666 | | $1,311,718 |
| | | 2009 | | 2008 | | 2012 | | 2011 |
| Entergy Mississippi | | | | | | | | |
| Audit Fees | | $881,277 | | $880,674 | | $945,666 | | $971,218 |
| Audit-Related Fees (a) | | - | | - | | - | | - |
| | | | | | | | | |
| Total audit and audit-related fees | | 881,277 | | 880,674 | | 945,666 | | 971,218 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $881,277 | | $880,674 | | $945,666 | | $971,218 |
| | | | | | | | | |
| Entergy New Orleans | | | | | | | | |
| Audit Fees | | $777,218 | | $806,658 | | $945,666 | | $901,218 |
| Audit-Related Fees (a) | | - | | - | | - | | - |
| | | | | | | | | |
| Total audit and audit-related fees | | 777,218 | | 806,658 | | 945,666 | | 901,218 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $777,218 | | $806,658 | | $945,666 | | $901,218 |
| | | | | | | | | |
| Entergy Texas | | | | | | | | |
| Audit Fees | | $1,896,277 | | $1,129,174 | | $998,666 | | $1,945,188 |
| Audit-Related Fees (a) | | 200,000 | | - | | - | | - |
| | | | | | | | | |
| Total audit and audit-related fees | | 2,096,277 | | 1,129,174 | | 998,666 | | 1,945,188 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $2,096,277 | | $1,129,174 | | $998,666 | | $1,945,188 |
| | | | | | | | | |
| System Energy | | | | | | | | |
| Audit Fees | | $826,828 | | $836,231 | | $945,666 | | $901,218 |
| Audit-Related Fees (a) | | 103,230 | | - | | - | | - |
| | | | | | | | | |
| Total audit and audit-related fees | | 930,058 | | 836,231 | | 945,666 | | 901,218 |
| Tax Fees | | - | | - | | - | | - |
| All Other Fees | | - | | - | | - | | - |
| | | | | | | | | |
| Total Fees (c) | | $930,058 | | $836,231 | | $945,666 | | $901,218 |
| (a) | Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services. |
| (b) | Includes fees for tax return review and tax compliance assistance.advisory services. |
| (c) | 100% of fees paid in 20092012 and 20082011 were pre-approved by the Entergy Corporation Audit Committee. |
Entergy Audit Committee Guidelines for Pre-approval of Independent Auditor Services
The Audit Committee has adopted the following guidelines regarding the engagement of Entergy'sEntergy’s independent auditor to perform services for Entergy:
| 1. | The independent auditor will provide the Audit Committee, for approval, an annual engagement letter outlining the scope of services proposed to be performed during the fiscal year, including audit services and other permissible non-audit services (e.g. audit-related services, tax services, and all other services). |
| 2. | For other permissible services not included in the engagement letter, Entergy management will submit a description of the proposed service, including a budget estimate, to the Audit Committee for pre-approval. Management and the independent auditor must agree that the requested service is consistent with the SEC'sSEC’s rules on auditor independence prior to submission to the Audit Committee. The Audit Committee, at its discretion, will pre-approve permissible services and has established the following additional guidelines for permissible non-audit services provided by the independent auditor: · Aggregate non-audit service fees are targeted at fifty percent or less of the approved audit service fee. · All other services should only be provided by the independent auditor if it is the only qualified provider of that service or if the Audit Committee specifically requests the service. |
| 3. | The Audit Committee will be informed quarterly as to the status of pre-approved services actually provided by the independent auditor. |
| 4. | To ensure prompt handling of unexpected matters, the Audit Committee delegates to the Audit Committee Chair or its designee the authority to approve permissible services and fees. The Audit Committee Chair or designee will report action taken to the Audit Committee at the next scheduled Audit Committee meeting. |
| 5. | The Vice President and General Auditor will be responsible for tracking all independent auditor fees and will report quarterly to the Audit Committee. |
PART IV
| (a)1. | Financial Statements and Independent Auditors'Auditors’ Reports for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Table of Contents. |
| | |
| (a)2. | Financial Statement Schedules Report of Independent Registered Public Accounting Firm (see page 489)513) Financial Statement Schedules are listed in the Index to Financial Statement Schedules (see page S-1) |
| | |
| (a)3. | Exhibits Exhibits for Entergy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy are listed in the Exhibit Index (see page E-1). Each management contract or compensatory plan or arrangement required to be filed as an exhibit hereto is identified as such by footnote in the Exhibit Index. |
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY CORPORATION By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 24, 201027, 2013 |
J. Wayne LeonardLeo P. Denault (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Leo P. DenaultAndrew S. Marsh (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, W. Frank Blount, Gary W. Edwards, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Stewart C. Myers, James R. Nichols, William A. Percy, II, W. J. Tauzin, and Steven V. Wilkinson (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 2010 |
| 27, 2013 |
ENTERGY ARKANSAS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY ARKANSAS, INC. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
Hugh T. McDonald (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Leo P. Denault,Theodore H. Bunting, Jr., Andrew S. Marsh, and Mark T. Savoff and Gary J. Taylor (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
ENTERGY GULF STATES LOUISIANA, L.L.C.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY GULF STATES LOUISIANA, L.L.C. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
E. Renae Conley (ChairPhillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Leo P. Denault,Theodore H. Bunting, Jr., Andrew S. Marsh, and Mark T. Savoff and Gary J. Taylor (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
ENTERGY LOUISIANA, LLC
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY LOUISIANA, LLC By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
E. Renae Conley (ChairPhillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Leo P. Denault,Theodore H. Bunting, Jr., Andrew S. Marsh, and Mark T. Savoff and Gary J. Taylor (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
ENTERGY MISSISSIPPI, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY MISSISSIPPI, INC. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Leo P. Denault,Theodore H. Bunting, Jr., Andrew S. Marsh, and Mark T. Savoff and Gary J. Taylor (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
ENTERGY NEW ORLEANS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY NEW ORLEANS, INC. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
Roderick K. WestCharles L. Rice, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Gary J. Taylor,Theodore H. Bunting, Jr. and Sherri WinslowMark T. Savoff (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
ENTERGY TEXAS, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
ENTERGY TEXAS, INC. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer and acting Principal Financial Officer) | February 24, 201027, 2013 |
Joseph F. Domino (ChairmanSallie T. Rainer (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Leo P. Denault,Theodore H. Bunting, Jr., Andrew S. Marsh, and Mark T. Savoff and Gary J. Taylor (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
SYSTEM ENERGY RESOURCES, INC.
SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. The signature of the undersigned company shall be deemed to relate only to matters having reference to such company and any subsidiaries thereof.
SYSTEM ENERGY RESOURCES, INC. By /s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
Senior Vice President and Chief Accounting Officer Date: February 24, 201027, 2013 |
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. The signature of each of the undersigned shall be deemed to relate only to matters having reference to the above-named company and any subsidiaries thereof.
| Signature | Title | Date |
| | | |
| | | |
/s/ Theodore H. Bunting, Jr.Alyson M. Mount Theodore H. Bunting, Jr.Alyson M. Mount
| Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 24, 201027, 2013 |
John T. HerronJeffrey S. Forbes (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Wanda C. Curry (Vice President, Chief Financial Officer - Nuclear Operations; Principal Financial Officer); Leo P. DenaultAndrew S. Marsh and Steven C. McNeal (Directors).
By: /s/ Theodore H. Bunting, Jr.Alyson M. Mount (Theodore H. Bunting, Jr.,Alyson M. Mount, Attorney-in-fact) | February 24, 201027, 2013 |
| CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM |
We consent to the incorporation by reference in Post-Effective Amendments Nos. 1, 2, and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-169315, Post-Effective Amendments Nos. 3 and 5A on Form S-8 and their related prospectuses to Registration Statement No. 33-54298 on Form S-4, and in Registration Statements Nos. 333-55692, 333-68950, 333-75097, 333-90914, 333-98179, 333-140183, 333-142055, 333-168664, 333-174148, and 333-142055333-183090 on Form S-8 of our reports dated February 24, 2010,27, 2013, relating to the consolidated financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the adoption of a new accounting standard regarding non-controlling interests), consolidated financial statement schedule, and the effectiveness of Entergy Corporation and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Corporation and Subsidiaries for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 1, 2, and 3 on Form S-3, and their related prospectus to Registration Statement No. 333-159157333-169315-03 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the consolidated financial statements and financial statement schedule of Entergy Arkansas, Inc., and Subsidiaries, and the effectiveness of Entergy Arkansas, Inc.’s and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Registration Statement No. 333-156435Post-Effective Amendments Nos. 1, 2, and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-153623333-169315-02 on Form S-4S-3 of our reports dated February 24, 2010,27, 2013, relating to the financial statements and financial statement schedule of Entergy Gulf States Louisiana, L.L.C. (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the effects of the distribution of certain assets and liabilities to Entergy Texas, Inc. and Subsidiaries as part of a jurisdictional separation plan), financial statement schedule, and the effectiveness of Entergy Gulf States Louisiana, L.L.C.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Gulf States Louisiana, L.L.C. for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 1, 2, and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-159158333-169315-01 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the consolidated financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries, and the effectiveness of Entergy Louisiana, LLC’sLLC and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Louisiana, LLC for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 2 and 3 on Form S-3 and their related prospectus to Registration StatementsStatement No. 333-159164333-169315-07 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the financial statements and financial statement schedule of Entergy Mississippi, Inc., and the effectiveness of Entergy Mississippi, Inc.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 2 and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-155584333-169315-06 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the financial statements and financial statement schedule of Entergy New Orleans, Inc., and the effectiveness of Entergy New Orleans, Inc.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 2 and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-153442333-169315-05 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the consolidated financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries, (which report expresses an unqualified opinion and includes an explanatory paragraph regarding the effects of distribution of certain assets and liabilities from Entergy Gulf States, Inc. to Entergy Texas, Inc. and Subsidiaries as part of the jurisdictional separation plan), financial statement schedule, and the effectiveness of Entergy Texas, Inc. and Subsidiaries’ internal control over financial reporting, appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. and Subsidiaries for the year ended December 31, 2009.2012.
We consent to the incorporation by reference in Post-Effective Amendments Nos. 2 and 3 on Form S-3 and their related prospectus to Registration Statement No. 333-156718333-169315-04 on Form S-3 of our reports dated February 24, 2010,27, 2013, relating to the financial statements of System Energy Resources, Inc., and the effectiveness of System Energy Resources, Inc.’s internal control over financial reporting, appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2009.2012.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
To the Board of Directors and Shareholders of
Entergy Corporation and Subsidiaries
Entergy Arkansas, Inc. and Subsidiaries
Entergy Mississippi, Inc.
Entergy New Orleans, Inc.
Entergy Texas, Inc. and Subsidiaries
To the Board of Directors and Members of
Entergy Gulf States Louisiana, L.L.C.
Entergy Louisiana, LLC and Subsidiaries
We have audited the consolidated financial statements of Entergy Corporation and Subsidiaries, (the “Corporation”)Entergy Arkansas, Inc. and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, (“ETI”), and we have also audited the financial statements of Entergy Arkansas, Inc., Entergy Gulf States Louisiana, L.L.C., Entergy Louisiana, LLC, Entergy Mississippi, Inc., and Entergy New Orleans, Inc. (collectively the “Companies”) as of December 31, 20092012 and 2008,2011, and for each of the three years in the period ended December 31, 2009, and the Corporation’s, ETI's,2012, and the respective Companies’ internal control over financial reporting as of December 31, 2009,2012, and have issued our reports thereon dated February 24, 2010;27, 2013; such reports are included elsewhere in this Form 10-K. Our report on the consolidated financial statements of the Corporation expressed an unqualified opinion and included an explanatory paragraph relating to the adoption of a new accounting standard regarding non-controlling interests. Our report on the financial statements of Entergy Gulf States Louisiana, L.L.C. expressed an unqualified opinion and included an explanatory paragraph regarding the effects of the distribution of certain assets and liabilities to ETI as part of a jurisdictional separation plan. Our report on the consolidated financial statements of ETI expressed an unqualified opinion and included an explanatory paragraph regarding the effects of the distribution of certain assets and liabilities from Entergy Gulf States, Inc. to ETI as part of a jurisdictional separation plan. Our audits also included the financial statement schedules of the Corporation, ETI, and the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the Corporation’s, ETI’s, and the respective Companies’ management. Our responsibility is to express an opinion based on our audits. In our opinion, such financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 24, 201027, 2013
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| Schedule | | Page |
| | | |
| II | Valuation and Qualifying Accounts 2009, 20082012, 2011, and 2007:2010: | |
| | Entergy Corporation and Subsidiaries | S-2 |
| | Entergy Arkansas, Inc. and Subsidiaries | S-3 |
| | Entergy Gulf States Louisiana, L.L.C. | S-4 |
| | Entergy Louisiana, LLC and Subsidiaries | S-5 |
| | Entergy Mississippi, Inc. | S-6 |
| | Entergy New Orleans, Inc. | S-7 |
| | Entergy Texas, Inc. and Subsidiaries | S-8 |
Schedules other than those listed above are omitted because they are not required, not applicable, or the required information is shown in the financial statements or notes thereto.
Columns have been omitted from schedules filed because the information is not applicable.
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 31,159 | | | $ | 2,448 | | | $ | 1,651 | | | $ | 31,956 | |
| 2011 | | $ | 31,777 | | | $ | 512 | | | $ | 1,130 | | | $ | 31,159 | |
| 2010 | | $ | 27,631 | | | $ | 1,569 | | | $ | (2,577 | ) | | $ | 31,777 | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY CORPORATION AND SUBSIDIARIES | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 25,610 | | | $ | 2,021 | | | $ | - | | | $ | 27,631 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 147,452 | | | $ | 52,050 | | | $ | 58,187 | | | $ | 141,315 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 25,789 | | | $ | (179 | ) | | $ | - | | | $ | 25,610 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 133,406 | | | $ | 56,826 | | | $ | 42,780 | | | $ | 147,452 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 29,911 | | | $ | (4,122 | ) | | $ | - | | | $ | 25,789 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 97,287 | | | $ | 63,262 | | | $ | 27,143 | | | $ | 133,406 | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 26,155 | | | $ | 2,188 | | | $ | - | | | $ | 28,343 | |
| 2011 | | $ | 24,402 | | | $ | 1,753 | | | $ | - | | | $ | 26,155 | |
| 2010 | | $ | 21,853 | | | $ | 2,549 | | | $ | - | | | $ | 24,402 | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 19,882 | | | $ | 1,971 | | | $ | - | | | $ | 21,853 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 15,925 | | | $ | 17,076 | | | $ | 19,784 | | | $ | 13,217 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 16,649 | | | $ | 3,233 | | | $ | - | | | $ | 19,882 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 14,414 | | | $ | 1,397 | | | $ | (114 | ) | | $ | 15,925 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 15,257 | | | $ | 1,392 | | | $ | - | | | $ | 16,649 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 14,539 | | | $ | 5,219 | | | $ | 5,344 | | | $ | 14,414 | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,230 | | | $ | 5 | | | $ | - | | | $ | 1,235 | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Not Deducted from Assets (2) | | $ | 13,896 | | | $ | 7,660 | | | $ | 6,887 | | | $ | 14,669 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 979 | | | $ | 251 | | | $ | - | | | $ | 1,230 | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Not Deducted from Assets (2) | | $ | 11,887 | | | $ | 20,059 | | | $ | 18,050 | | | $ | 13,896 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 759 | | | $ | 220 | | | $ | - | | | $ | 979 | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Not Deducted from Assets (2) | | $ | 21,245 | | | $ | 21,183 | | | $ | 30,541 | | | $ | 11,887 | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY GULF STATES LOUISIANA, L.L.C. | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 843 | | | $ | 123 | | | $ | 255 | | | $ | 711 | |
| 2011 | | $ | 1,306 | | | $ | (235 | ) | | $ | 228 | | | $ | 843 | |
| 2010 | | $ | 1,235 | | | $ | (413 | ) | | $ | (484 | ) | | $ | 1,306 | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| | | | | | | | | | | | | | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,698 | | | $ | (386 | ) | | $ | - | | | $ | 1,312 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 19,916 | | | $ | 7,851 | | | $ | 7,466 | | | $ | 20,301 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,988 | | | $ | (290 | ) | | $ | - | | | $ | 1,698 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 18,405 | | | $ | 17,450 | | | $ | 15,939 | | | $ | 19,916 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,856 | | | $ | 132 | | | $ | - | | | $ | 1,988 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 23,798 | | | $ | 22,910 | | | $ | 28,303 | | | $ | 18,405 | |
| | | | | | | | | | | | | | | | | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 1,147 | | | $ | 121 | | | $ | 401 | | | $ | 867 | |
| 2011 | | $ | 1,961 | | | $ | (453 | ) | | $ | 361 | | | $ | 1,147 | |
| 2010 | | $ | 1,312 | | | $ | (112 | ) | | $ | (761 | ) | | $ | 1,961 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 756 | | | $ | 154 | | | $ | - | | | $ | 910 | |
| 2011 | | $ | 985 | | | $ | (229 | ) | | $ | - | | | $ | 756 | |
| 2010 | | $ | 1,018 | | | $ | (33 | ) | | $ | - | | | $ | 985 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 687 | | | $ | 331 | | | $ | - | | | $ | 1,018 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 36,957 | | | $ | 11,411 | | | $ | 6,965 | | | $ | 41,403 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 615 | | | $ | 72 | | | $ | - | | | $ | 687 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 50,264 | | | $ | 10,175 | | | $ | 23,482 | | | $ | 36,957 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 615 | | | $ | - | | | $ | - | | | $ | 615 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 10,036 | | | $ | 2,519 | | | $ | (37,709 | ) | | $ | 50,264 | |
| | | | | | | | | | | | | | | | | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 465 | | | $ | 12 | | | $ | 31 | | | $ | 446 | |
| 2011 | | $ | 734 | | | $ | (241 | ) | | $ | 28 | | | $ | 465 | |
| 2010 | | $ | 1,166 | | | $ | (491 | ) | | $ | (59 | ) | | $ | 734 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,112 | | | $ | 54 | | | $ | - | | | $ | 1,166 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 10,609 | | | $ | 2,187 | | | $ | (3,195 | ) | | $ | 15,991 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 4,639 | | | $ | (3,527 | ) | | $ | - | | | $ | 1,112 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 14,329 | | | $ | 1,507 | | | $ | 5,227 | | | $ | 10,609 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 10,563 | | | $ | (5,924 | ) | | $ | - | | | $ | 4,639 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 8,385 | | | $ | 1,062 | | | $ | (4,882 | ) | | $ | 14,329 | |
| | | | | | | | | | | | | | | | | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| | | | | | | | | | | | | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| Years Ended December 31, 2009, 2008, and 2007 | |
| (In Thousands) | |
| | | | | | | | | | | | | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | Other | | | | |
| | | | | | Additions | | | Changes | | | | |
| | | | | | Charged to | | | Deductions | | | | |
| | | Balance at | | | Income or | | | from | | | Balance | |
| | | Beginning | | | Regulatory | | | Provisions | | | at End | |
| Description | | of Period | | | Assets | | | | (1) | | | of Period | |
| Year ended December 31, 2009 | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 1,001 | | | $ | (157 | ) | | $ | - | | | $ | 844 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 12,936 | | | $ | 4,944 | | | $ | 9,170 | | | $ | 8,710 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2008 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 918 | | | $ | 83 | | | $ | - | | | $ | 1,001 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 8,863 | | | $ | 4,885 | | | $ | 812 | | | $ | 12,936 | |
| | | | | | | | | | | | | | | | | |
| Year ended December 31, 2007 | | | | | | | | | | | | | | | | |
| Accumulated Provisions | | | | | | | | | | | | | | | | |
| Deducted from Assets-- | | | | | | | | | | | | | | | | |
| Doubtful Accounts | | $ | 859 | | | $ | 59 | | | $ | - | | | $ | 918 | |
| Accumulated Provisions Not | | | | | | | | | | | | | | | | |
| Deducted from Assets (2) | | $ | 9,431 | | | $ | 5,311 | | | $ | 5,879 | | | $ | 8,863 | |
| | | | | | | | | | | | | | | | | |
| ___________ | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions from provisions represent losses or expenses for which the respective provisions were | | | | | |
| created. In the case of the provision for doubtful accounts, such deductions are reduced by recoveries | | | | | |
| of amounts previously written off. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| (2) Accumulated provisions not deducted from assets includes provisions for property insurance, injuries and damages, environmental, | |
| and pension related items. | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| | |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | |
| For the Years Ended December 31, 2012, 2011, and 2010 | |
| (In Thousands) | |
| | |
| Column A | | Column B | | | Column C | | | Column D | | | Column E | |
| | | | | | | | | | | | | |
| | | Balance at | | | | | | Other | | | Balance | |
| | | Beginning | | | Additions | | | Changes | | | at End | |
| Description | | of Period | | | Charged to Income | | | Deductions (1) | | | of Period | |
| Allowance for doubtful accounts | | | | | | | | | | | | |
| 2012 | | $ | 1,461 | | | $ | (21 | ) | | $ | 760 | | | $ | 680 | |
| 2011 | | $ | 2,185 | | | $ | (212 | ) | | $ | 512 | | | $ | 1,461 | |
| 2010 | | $ | 844 | | | $ | 69 | | | $ | (1,272 | ) | | $ | 2,185 | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Notes: | | | | | | | | | | | | | | | | |
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
The following exhibits indicated by an asterisk preceding the exhibit number are filed herewith. The balance of the exhibits have heretofore been filed with the SEC as the exhibits and in the file numbers indicated and are incorporated herein by reference. The exhibits marked with a (+) are management contracts or compensatory plans or arrangements required to be filed herewith and required to be identified as such by Item 15 of Form 10-K. Reference is made to a duplicate list of exhibits being filed as a part of this Form 10-K, which list, prepared in accordance with Item 102 of Regulation S-T of the SEC, immediately precedes the exhibits being physically filed with this Form 10-K.
Some of the agreements included or incorporated by reference as exhibits to this Form 10-K contain representations and warranties by each of the parties to the applicable agreement. These representations and warranties were made solely for the benefit of the other parties to the applicable agreement and (i) were not intended to be treated as categorical statements of fact, but rather as a way of allocating the risk to one of the parties if those statements prove to be inaccurate; (ii) may have been qualified in such agreement by disclosures that were made to the other party in connection with the negotiation of the applicable agreement; (iii) may apply contract standards of “materiality” that are different from the standard of “materiality” under the applicable securities laws; and (iv) were made only as of the date of the applicable agreement or such other date or dates as may be specified in the agreement.
Entergy acknowledges that, notwithstanding the inclusion of the foregoing cautionary statements, it is responsible for considering whether additional specific disclosures of material information regarding material contractual provisions are required to make the statements in this Form 10-K not misleading.
| (2) Plan of Acquisition, Reorganization, Arrangement, Liquidation or Succession |
| (a) 1 -- | Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and Ibis Transaction Subsidiary LLC (2.1 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
| (a) 2 -- | Amendment No. 1, dated as of September 21, 2012, to the Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (included in Annex A to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Corporation agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.) |
| |
| (a) 3 -- | Amendment No. 2, dated as of January 28, 2013, to the Merger Agreement, dated as of December 4, 2011, among Entergy Corporation, Mid South TransCo LLC, ITC Holdings Corp. and ITC Midsouth LLC (formerly known as Ibis Transaction Subsidiary LLC) (included in Annex A to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). |
| |
| (a) 4 -- | Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
| (a) 5 -- | Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Corporation agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.) |
| Entergy Gulf States Louisiana |
(a)(b) 1 -- | Plan of Merger of Entergy Gulf States, Inc. effective December 31, 2007 (2(ii) to Form 8-K15D5 datedfiled January 7, 2008 in 333-148557). |
| |
| (b) 2 -- | Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
| (b) 3 -- | Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Gulf States Louisiana agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.) |
| Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| (c) 1 -- | Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (2.2 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
| (c) 2 -- | Amendment No. 1, dated as of September 24, 2012, to the Separation Agreement, dated as of December 4, 2011, among Entergy Corporation, ITC Holdings Corp., Mid South TransCo LLC, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas and Entergy Services, Inc. (included in Annex B to the proxy statement/prospectus that forms a part of Amendment No. 2 to the Registration Statement on Form S-4 filed by ITC Holdings Corp. on January 28, 2013 (Registration No. 333-184073)). (The Exhibits listed and identified therein have been omitted pursuant to Item 601(b)(2) of Regulation S-K. Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each agrees that it will furnish supplementally a copy of any omitted Exhibit to the Securities and Exchange Commission upon request.) |
| (3) Articles of Incorporation and By-laws |
Entergy Corporation
| (a) 1 -- | Restated Certificate of Incorporation of Entergy Corporation dated October 10, 2006 (3(a) to Form 10-Q for the quarter ended September 30, 2006). |
| | |
| (a) 2 -- | By-Laws of Entergy Corporation as amended February 12, 2007, and as presently in effect (3(ii) to Form 8-K datedfiled February 16, 2007 in 1-11299). |
| (b) 1 -- | Amended and Restated Articles of Incorporation of System Energy and amendments thereto through April 28, 1989 (A-1(a) to Form U-1 in 70-5399). |
| | |
| (b) 2 -- | By-Laws of System Energy effective July 6, 1998, and as presently in effect (3(f) to Form 10-Q for the quarter ended June 30, 1998 in 1-9067). |
| (c) 1 -- | Articles of Amendment and Restatement for the Second Amended and Restated Articles of Incorporation of Entergy Arkansas, effective August 19, 2009 (3 to Form 8-K datedfiled August 24, 2009 in 1-10764). |
| | |
| (c) 2 -- | By-Laws of Entergy Arkansas effective November 26, 1999, and as presently in effect (3(ii)(c) to Form 10-K for the year ended December 31, 1999 in 1-10764). |
| Entergy Gulf States Louisiana |
| (d) 1 -- | Articles of Organization of Entergy Gulf States Louisiana effective December 31, 2007 (3(i) to Form 8-K15D5 datedfiled January 7, 2008 in 333-148557). |
| | |
| (d) 2 -- | Operating Agreement of Entergy Gulf States Louisiana, effective as of December 31, 2007 (3(ii) to Form 8-K15D5 datedfiled January 7, 2008 in 333-148557). |
| (e) 1 -- | Articles of Organization of Entergy Louisiana effective December 31, 2005 (3(c) to Form 8-K datedfiled January 6, 2006 in 1-32718). |
| | |
| (e) 2 -- | Regulations of Entergy Louisiana effective December 31, 2005, and as presently in effect (3(d) to Form 8-K datedfiled January 6, 2006 in 1-32718). |
| (f) 1 -- | Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K datedfiled July 27, 2009 in 1-31508). |
| | |
| (f) 2 -- | By-Laws of Entergy Mississippi effective November 26, 1999, and as presently in effect (3(ii)(f) to Form 10-K for the year ended December 31, 1999 in 0-320). |
| (g) 1 -- | Amended and Restated Articles of Incorporation of Entergy New Orleans, as amendedeffective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
| | |
| (g) 2 -- | Amended By-Laws of Entergy New Orleans as amendedeffective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
| (h) 1 -- | Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 datedfiled March 14, 2008 in 000-53134). |
| | |
| (h) 2 -- | By-LawsBylaws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 datedfiled March 14, 2008 in 000-53134). |
| (4) | Instruments Defining Rights of Security Holders, Including Indentures |
| (a) 1 -- | See (4)(b) through (4)(h) below for instruments defining the rights of holders of long-term debt of System Energy, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. |
| | |
| (a) 2 -- | AmendmentCredit Agreement ($3,500,000,000), dated as of March 9, 2012, among Entergy Corporation, as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, Bank of the West, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, National Cooperative Services Corporation, and The Northern Trust Company), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.1 to Form 8-K filed March 14, 2012 in 1-11299). |
| (a) 3 -- | Indenture (For Unsecured Debt Securities), dated as of September 21, 2005, to the Amended and Restated Credit Agreement, dated as of June 30, 2005, among1, 2010, between Entergy Corporation as Borrower, Bayerische Hypo- und Vereinsbank AG, New York Branch, asand Wells Fargo Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (4(b)National Association (4.01 to Form 8-K datedfiled September 28, 2005 in 1-11299). |
| |
(a) 3 -- | Amended and Restated Credit Agreement, dated as of June 30, 2005, among Entergy Corporation, as Borrower, Bayerische Hypo- und Vereinsbank AG, New York Branch, as Bank, and Bayerische Hypo-und Vereinsbank AG, New York Branch, as Administrative Agent (4(g) to Form 10-Q for the quarter ended June 30, 200516, 2010 in 1-11299). |
| | |
| (a) 4 -- | Credit Agreement ($3,500,000,000), dated as of August 2, 2007, amongOfficer’s Certificate for Entergy Corporation the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), J. P. Morgan Chase Bank, N.A., KeyBank National Association, Lehman Brothers Bank (FSB), Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, Regions Bank, Societe Generale, The Bank of New York, The Bank of Nova Scotia, The Bank of Toyko-Mitsubishi UFJ, Ltd. (New York Branch), The Royal Bank of Scotland plc, Union Bank of California, N.A., Wachovia Bank, National Association and William Street Commitment Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, and ABN AMRO Bank, N.V., as LC Issuing Bank (10(a)relating to 3.625% Senior Notes due September 15, 2015 (4.02(a) to Form 10-Q for the quarter ended June 30, 20078-K filed September 16, 2010 in 1-11299). |
| | |
| (a) 5 -- | Indenture, dated as of December 1, 2002, betweenOfficer’s Certificate for Entergy Corporation and Deutsche Bank Trust Company Americas, as Trustee (4(a)4relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 10-K for the year ended December 31, 20028-K filed September 16, 2010 in 1-11299). |
| | |
| (a) 6 -- | Supplemental No. 1, dated as of December 20, 2005, between Entergy Corporation and Deutsche Bank Trust Company Americas, as Trustee (4(a)11 to Form 10-K for the year ended December 31, 2005 in 1-11299). |
| |
(a) 7 -- | Officer'sOfficer’s Certificate for Entergy Corporation relating to 7.06%4.70% Senior Notes due MarchJanuary 15, 2011 (4(d)2017 (4.02 to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). |
| |
(a) 8 -- | Officer's Certificate for Entergy Corporation relating to 6.58% Senior Notes due May 15, 2010 (4(d) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299). |
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(a) 9 -- | Officer's Certificate for Entergy Corporation relating to 6.90% Senior Notes due November 15, 2010 (4(a)10 to Form 10-K for the year ended December 31, 20038-K filed January 13, 2012 in 1-11299). |
| (b) 1 -- | Mortgage and Deed of Trust, dated as of June 15, 1977, as amended by twenty-threetwenty-four Supplemental Indentures (A-1 in 70-5890 (Mortgage); B and C to Rule 24 Certificate in 70-5890 (First); B to Rule 24 Certificate in 70-6259 (Second); 20(a)-5 to Form 10-Q for the quarter ended June 30, 1981 in 1-3517 (Third); A-1(e)-1 to Rule 24 Certificate in 70-6985 (Fourth); B to Rule 24 Certificate in 70-7021 (Fifth); B to Rule 24 Certificate in 70-7021 (Sixth); A-3(b) to Rule 24 Certificate in 70-7026 (Seventh); A-3(b) to Rule 24 Certificate in 70-7158 (Eighth); B to Rule 24 Certificate in 70-7123 (Ninth); B-1 to Rule 24 Certificate in 70-7272 (Tenth); B-2 to Rule 24 Certificate in 70-7272 (Eleventh); B-3 to Rule 24 Certificate in 70-7272 (Twelfth); B-1 to Rule 24 Certificate in 70-7382 (Thirteenth); B-2 to Rule 24 Certificate in 70-7382 (Fourteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Fifteenth); A-2(c) to Rule 24 Certificate in 70-7946 (Sixteenth); A-2(d) to Rule 24 Certificate in 70-7946 (Seventeenth); A-2(e) to Rule 24 Certificate dated May 4, 1993 in 70-7946 (Eighteenth); A-2(g) to Rule 24 Certificate dated May 6, 1994 in 70-7946 (Nineteenth); A-2(a)(1) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twentieth); A-2(a)(2) to Rule 24 Certificate dated August 8, 1996 in 70-8511 (Twenty-first); A-2(a) to Rule 24 Certificate datedfiled October 4, 2002 in 70-9753 (Twenty-second); and 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third); and 4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)). |
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| (b) 2 -- | Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
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| (b) 3 -- | Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| (c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by sixty-eightseventy-two Supplemental Indentures (7(d) in 2-5463 (Mortgage); 7(b) in 2-7121 (First); 7(c) in 2-7605 (Second); 7(d) in 2-8100 (Third); 7(a)-4 in 2-8482 (Fourth); 7(a)-5 in 2-9149 (Fifth); 4(a)-6 in 2-9789 (Sixth); 4(a)-7 in 2-10261 (Seventh); 4(a)-8 in 2-11043 (Eighth); 2(b)-9 in 2-11468 (Ninth); 2(b)-10 in 2-15767 (Tenth); D in 70-3952 (Eleventh); D in 70-4099 (Twelfth); 4(d) in 2-23185 (Thirteenth); 2(c) in 2-24414 (Fourteenth); 2(c) in 2-25913 (Fifteenth); 2(c) in 2-28869 (Sixteenth); 2(d) in 2-28869 (Seventeenth); 2(c) in 2-35107 (Eighteenth); 2(d) in 2-36646 (Nineteenth); 2(c) in 2-39253 (Twentieth); 2(c) in 2-41080 (Twenty-first); C-1 to Rule 24 Certificate in 70-5151 (Twenty-second); C-1 to Rule 24 Certificate in 70-5257 (Twenty-third); C to Rule 24 Certificate in 70-5343 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-5404 (Twenty-fifth); C to Rule 24 Certificate in 70-5502 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-5556 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-5693 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6078 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6174 (Thirtieth); C-1 to Rule 24 Certificate in 70-6246 (Thirty-first); C-1 to Rule 24 Certificate in 70-6498 (Thirty-second); A-4b-2 to Rule 24 Certificate in 70-6326 (Thirty-third); C-1 to Rule 24 Certificate in 70-6607 (Thirty-fourth); C-1 to Rule 24 Certificate in 70-6650 (Thirty-fifth); C-1 to Rule 24 Certificate dated December 1, 1982 in 70-6774 (Thirty-sixth); C-1 to Rule 24 Certificate dated February 17, 1983 in 70-6774 (Thirty-seventh); A-2(a) to Rule 24 Certificate dated December 5, 1984 in 70-6858 (Thirty-eighth); A-3(a) to Rule 24 Certificate in 70-7127 (Thirty-ninth); A-7 to Rule 24 Certificate in 70-7068 (Fortieth); A-8(b) to Rule 24 Certificate dated July 6, 1989 in 70-7346 (Forty-first); A-8(c) to Rule 24 Certificate dated February 1, 1990 in 70-7346 (Forty-second); 4 to Form 10-Q for the quarter ended September 30, 1990 in 1-10764 (Forty-third); A-2(a) to Rule 24 Certificate dated November 30, 1990 in 70-7802 (Forty-fourth); A-2(b) to Rule 24 Certificate dated January 24, 1991 in 70-7802 (Forty-fifth); 4(d)(2) in 33-54298 (Forty-sixth); 4(c)(2) to Form 10-K for the year ended December 31, 1992 in 1-10764 (Forty-seventh); 4(b) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-eighth); 4(c) to Form 10-Q for the quarter ended June 30, 1993 in 1-10764 (Forty-ninth); 4(b) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fiftieth); 4(c) to Form 10-Q for the quarter ended September 30, 1993 in 1-10764 (Fifty-first); 4(a) to Form 10-Q for the quarter ended June 30, 1994 in 1-10764 (Fifty-second); C-2 to Form U5S for the year ended December 31, 1995 (Fifty-third); C-2(a) to Form U5S for the year ended December 31, 1996 (Fifty-fourth); 4(a) to Form 10-Q for the quarter ended March 31, 2000 in 1-10764 (Fifty-fifth); 4(a) to Form 10-Q for the quarter ended September 30, 2001 in 1-10764 (Fifty-sixth); C-2(a) to Form U5S for the year ended December 31, 2001 (Fifty-seventh); 4(c)1 to Form 10-K for the year December 31, 2002 in 1-10764 (Fifty-eighth); 4(a) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Fifty-ninth); 4(f) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixtieth); 4(h) to Form 10-Q for the quarter ended June 30, 2003 in 1-10764 (Sixty-first); 4(e) to Form 10-Q for the quarter ended September 30, 2004 in 1-10764 (Sixty-second); 4(c)1 to Form 10-K for the year December 31, 2004 in 1-10764 (Sixty-third); C-2(a) to Form U5S for the year ended December 31, 2004 (Sixty-fourth); 4(c) to Form 10-Q for the quarter ended June 30, 2005 in 1-10764 (Sixty-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 20052006 in 1-10764 (Sixty-sixth); 4(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-10764 (Sixty-seventh); and 4(c)1 to Form 10-K for the year ended December 31, 2008 in 1-10764 (Sixty-eighth); 4.06 to Form 8-K dated October 8, 2010 in 1-10764 (Sixty-ninth); 4.06 to Form 8-K dated November 12, 2010 in 1-10764 (Seventieth); 4.06 to Form 8-K dated December 13, 2012 in 1-10764 (Seventy-first); and 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second)). |
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| (c) 2 -- | Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Arkansas, Inc., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.2 to Form 8-K filed March 14, 2012 in 1-10764). |
| Entergy Gulf States Louisiana |
| (d) 1 -- | Indenture of Mortgage, dated September 1, 1926, as amended by certain Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9 in Registration No. 2-6893 (Seventh); B to Form 8-K dated September 1, 1959 (Eighteenth); B to Form 8-K dated February 1, 1966 (Twenty-second); B to Form 8-K dated March 1, 1967 (Twenty-third); C to Form 8-K dated March 1, 1968 (Twenty-fourth); B to Form 8-K dated November 1, 1968 (Twenty-fifth); B to Form 8-K dated April 1, 1969 (Twenty-sixth); 2-A-8 in Registration No. 2-66612 (Thirty-eighth); 4-2 to Form 10-K for the year ended December 31, 1984 in 1-27031 (Forty-eighth); 4-2 to Form 10-K for the year ended December 31, 1988 in 1-27031 (Fifty-second); 4 to Form 10-K for the year ended December 31, 1991 in 1-27031 (Fifty-third); 4 to Form 8-K dated July 29, 1992 in 1-27031 (Fifth-fourth); 4 to Form 10-K dated December 31, 1992 in 1-27031 (Fifty-fifth); 4 to Form 10-Q for the quarter ended March 31, 1993 in 1-27031 (Fifty-sixth); 4-2 to Amendment No. 9 to Registration No. 2-76551 (Fifty-seventh); 4(b) to Form 10-Q for the quarter ended March 31,1999 in 1-27031 (Fifty-eighth); A-2(a) to Rule 24 Certificate dated June 23, 2000 in 70-8721 (Fifty-ninth); A-2(a) to Rule 24 Certificate dated September 10, 2001 in 70-9751 (Sixtieth); A-2(b) to Rule 24 Certificate dated November 18, 2002 in 70-9751 (Sixty-first); A-2(c) to Rule 24 Certificate dated December 6, 2002 in 70-9751 (Sixty-second); A-2(d) to Rule 24 Certificate dated June 16, 2003 in 70-9751 (Sixty-third); A-2(e) to Rule 24 Certificate dated June 27, 2003 in 70-9751 (Sixty-fourth); A-2(f) to Rule 24 Certificate dated July 11, 2003 in 70-9751 (Sixty-fifth); A-2(g) to Rule 24 Certificate dated July 28, 2003 in 70-9751 (Sixty-sixth); A-3(i) to Rule 24 Certificate dated November 4, 2004 in 70-10158 (Sixty-seventh); A-3(ii) to Rule 24 Certificate dated November 23, 2004 in 70-10158 (Sixty-eighth); A-3(iii) to Rule 24 Certificate dated February 16, 2005 in 70-10158 (Sixty-ninth); A-3(iv) to Rule 24 Certificate dated June 2, 2005 in 70-10158 (Seventieth); A-3(v) to Rule 24 Certificate dated July 21, 2005 in 70-10158 (Seventy-first); A-3(vi) to Rule 24 Certificate dated October 7, 2005 in 70-10158 (Seventy-second); A-3(vii) to Rule 24 Certificate dated December 19, 2005 in 70-10158 (Seventy-third); 4(a) to Form 10-Q for the quarter ended March 31, 2006 in 1-27031 (Seventy-fourth); 4(iv) to Form 8-K15D5 dated January 7, 2008 in 333-148557 (Seventy-fifth); 4(a) to Form 10-Q for the quarter ended June 30, 2008 in 333-148557 (Seventy-sixth); and 4(a) to Form 10-Q for the quarter ended September 30, 2009 in 0-20371 (Seventy-seventh); 4.07 to Form 8-K dated October 1, 2010 in 0-20371 (Seventy-eighth); 4(c) to Form 8-K filed October 12, 2010 in 0-20371 (Seventy-ninth); and 4(f) to Form 8-K filed October 12, 2010 in 0-20371 (Eightieth)). |
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| (d) 2 -- | Indenture, dated March 21, 1939, accepting resignation of The Chase National Bank of the City of New York as trustee and appointing Central Hanover Bank and Trust Company as successor trustee (B-a-1-6 in Registration No. 2-4076). |
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| (d) 3 -- | Agreement of Resignation, Appointment and Acceptance, dated as of October 3, 2007, among Entergy Gulf States, Inc., JPMorgan Chase Bank, National Association, as resigning trustee, and The Bank of New York, as successor trustee (4(a) to Form 10-Q for the quarter ended September 30, 2007 in 1-27031). |
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(d) 4 -- | Credit Agreement ($200,000,000), dated as of August 2, 2007, among Entergy Gulf States, Inc., the Banks (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), JPMorgan Chase Bank, N.A., KeyBank National Association, Mizuho Corporate Bank, Ltd., Morgan Stanley Bank, The Bank of New York, The Royal Bank of Scotland plc, and Wachovia Bank, National Association), Citibank, N.A., as Administrative Agent, and the LC Issuing Banks (10(c) to Form 10-Q for the quarter ended June 30, 2007 in 1-27031). |
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(d) 5 -- | Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134). |
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| (d) 5 -- | Credit Agreement ($150,000,000), dated as of March 9, 2012, among Entergy Gulf States Louisiana, L.L.C., as borrower, the Banks named therein (Citibank, N.A., JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, N.A., The Royal Bank of Scotland plc, BNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.3 to Form 8-K filed March 14, 2012 in 0-20371). |
*(e) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by sixty-sixseventy-six Supplemental Indentures (7(d) in 2-5317 (Mortgage); 7(b) in 2-7408 (First); 7(c) in 2-8636 (Second); 4(b)-3 in 2-10412 (Third); 4(b)-4 in 2-12264 (Fourth); 2(b)-5 in 2-12936 (Fifth); D in 70-3862 (Sixth); 2(b)-7 in 2-22340 (Seventh); 2(c) in 2-24429 (Eighth); 4(c)-9 in 2-25801 (Ninth); 4(c)-10 in 2-26911 (Tenth); 2(c) in 2-28123 (Eleventh); 2(c) in 2-34659 (Twelfth); C to Rule 24 Certificate in 70-4793 (Thirteenth); 2(b)-2 in 2-38378 (Fourteenth); 2(b)-2 in 2-39437 (Fifteenth); 2(b)-2 in 2-42523 (Sixteenth); C to Rule 24 Certificate in 70-5242 (Seventeenth); C to Rule 24 Certificate in 70-5330 (Eighteenth); C-1 to Rule 24 Certificate in 70-5449 (Nineteenth); C-1 to Rule 24 Certificate in 70-5550 (Twentieth); A-6(a) to Rule 24 Certificate in 70-5598 (Twenty-first); C-1 to Rule 24 Certificate in 70-5711 (Twenty-second); C-1 to Rule 24 Certificate in 70-5919 (Twenty-third); C-1 to Rule 24 Certificate in 70-6102 (Twenty-fourth); C-1 to Rule 24 Certificate in 70-6169 (Twenty-fifth); C-1 to Rule 24 Certificate in 70-6278 (Twenty-sixth); C-1 to Rule 24 Certificate in 70-6355 (Twenty-seventh); C-1 to Rule 24 Certificate in 70-6508 (Twenty-eighth); C-1 to Rule 24 Certificate in 70-6556 (Twenty-ninth); C-1 to Rule 24 Certificate in 70-6635 (Thirtieth); C-1 to Rule 24 Certificate in 70-6834 (Thirty-first); C-1 to Rule 24 Certificate in 70-6886 (Thirty-second); C-1 to Rule 24 Certificate in 70-6993 (Thirty-third); C-2 to Rule 24 Certificate in 70-6993 (Thirty-fourth); C-3 to Rule 24 Certificate in 70-6993 (Thirty-fifth); A-2(a) to Rule 24 Certificate in 70-7166 (Thirty-sixth); A-2(a) in 70-7226 (Thirty-seventh); C-1 to Rule 24 Certificate in 70-7270 (Thirty-eighth); 4(a) to Quarterly Report on Form 10-Q for the quarter ended June 30, 1988 in 1-8474 (Thirty-ninth); A-2(b) to Rule 24 Certificate in 70-7553 (Fortieth); A-2(d) to Rule 24 Certificate in 70-7553 (Forty-first); A-3(a) to Rule 24 Certificate in 70-7822 (Forty-second); A-3(b) to Rule 24 Certificate in 70-7822 (Forty-third); A-2(b) to Rule 24 Certificate in 70-7822 (Forty-fourth); A-3(c) to Rule 24 Certificate in 70-7822 (Forty-fifth); A-2(c) to Rule 24 Certificate dated April 7, 1993 in 70-7822 (Forty-sixth); A-3(d) to Rule 24 Certificate dated June 4, 1993 in 70-7822 (Forth-seventh); A-3(e) to Rule 24 Certificate dated December 21, 1993 in 70-7822 (Forty-eighth); A-3(f) to Rule 24 Certificate dated August 1, 1994 in 70-7822 (Forty-ninth); A-4(c) to Rule 24 Certificate dated September 28, 1994 in 70-7653 (Fiftieth); A-2(a) to Rule 24 Certificate dated April 4, 1996 in 70-8487 (Fifty-first); A-2(a) to Rule 24 Certificate dated April 3, 1998 in 70-9141 (Fifty-second); A-2(b) to Rule 24 Certificate dated April 9, 1999 in 70-9141 (Fifty-third); A-3(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141 (Fifty-fourth); A-2(c) to Rule 24 Certificate dated June 2, 2000 in 70-9141 (Fifty-fifth); A-2(d) to Rule 24 Certificate dated April 4, 2002 in 70-9141 (Fifty-sixth); A-3(a) to Rule 24 Certificate dated March 30, 2004 in 70-10086 (Fifty-seventh); A-3(b) to Rule 24 Certificate dated October 15, 2004 in 70-10086 (Fifty-eighth); A-3(c) to Rule 24 Certificate dated October 26, 2004 in 70-10086 (Fifty-ninth); A-3(d) to Rule 24 Certificate dated May 18, 2005 in 70-10086 (Sixtieth); A-3(e) to Rule 24 Certificate dated August 25, 2005 in 70-10086 (Sixty-first); A-3(f) to Rule 24 Certificate dated October 31, 2005 in 70-10086 (Sixty-second); B-4(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-third); B-4(ii) to Rule 24 Certificate dated January 10, 2006 in 70-10324 (Sixty-fourth); 4(a) to Form 10-Q for the quarter ended September 30, 2008 in 1-32718 (Sixty-fifth); 4(e)1 to Form 10-K for the year ended December 31, 2009 in 1-132718 (Sixty-sixth); 4(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-32718 (Sixty-seventh); 4.08 to Form 8-K dated September 24, 2010 in 1-32718 (Sixty-eighth); 4(c) to Form 8-K filed October 12, 2010 in 1-32718 (Sixty-ninth); 4.08 to Form 8-K dated November 23, 2010 in 1-32718 (Seventieth); 4.08 to Form 8-K dated March 24, 2011 in 1-32718 (Seventy-first); 4(a) to Form 10-Q for the quarter ended June 30, 2011 in 1-32718 (Seventy-second); 4.08 to Form 8-K dated December 15, 2011 in 1-32718 (Seventy-third); 4.08 to Form 8-K dated January 12, 2012 in 1-32718 (Seventy-fourth); 4.08 to Form 8-K dated July 3, 2012 in 1-32718 (Seventy-fifth); and (Sixty-sixth)4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth)). |
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| (e) 2 -- | Facility Lease No. 1, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-1 in Registration No. 33-30660), as supplemented by Lease Supplement No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 1, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 2 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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| (e) 3 -- | Facility Lease No. 2, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-2 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 2, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 3 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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| (e) 4 -- | Facility Lease No. 3, dated as of September 1, 1989, between First National Bank of Commerce, as Owner Trustee, and Entergy Louisiana (4(c)-3 in Registration No. 33-30660), as supplemented by Lease Supplemental No. 1 dated as of July 1, 1997 (attached to Refunding Agreement No. 3, dated as of June 27, 1997, with such Refunding Agreement filed as Exhibit 4 to Current Report on Form 8-K, dated July 14, 1997 in 1-8474). |
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| (e) 5 -- | Credit Agreement ($200,000,000), dated as of August 2, 2007,March 9, 2012, among Entergy Louisiana, LLC, as borrower, the Banks named therein (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), JPMorgan Chase Bank, N.A., KeyBankWells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, The Bank of New York,N.A., The Royal Bank of Scotland plc, and WachoviaBNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association)Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and theLC Issuing Bank, JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, (10(b)and the other LC Issuing Banks from time to time parties thereto (4.4 to Form 10-Q for the quarter ended June 30, 20078-K filed March 14, 2012 in 1-11299)1-32718). |
| (f) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by twenty-sixthirty Supplemental Indentures (A-2(a)-2 to Rule 24 Certificate in 70-7461 (Mortgage); A-2(b)-2 in 70-7461 (First); A-5(b) to Rule 24 Certificate in 70-7419 (Second); A-4(b) to Rule 24 Certificate in 70-7554 (Third); A-1(b)-1 to Rule 24 Certificate in 70-7737 (Fourth); A-2(b) to Rule 24 Certificate dated November 24, 1992 in 70-7914 (Fifth); A-2(e) to Rule 24 Certificate dated January 22, 1993 in 70-7914 (Sixth); A-2(g) to Form U-1 in 70-7914 (Seventh); A-2(i) to Rule 24 Certificate dated November 10, 1993 in 70-7914 (Eighth); A-2(j) to Rule 24 Certificate dated July 22, 1994 in 70-7914 (Ninth); (A-2(l) to Rule 24 Certificate dated April 21, 1995 in 70-7914 (Tenth); A-2(a) to Rule 24 Certificate dated June 27, 1997 in 70-8719 (Eleventh); A-2(b) to Rule 24 Certificate dated April 16, 1998 in 70-8719 (Twelfth); A-2(c) to Rule 24 Certificate dated May 12, 1999 in 70-8719 (Thirteenth); A-3(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719 (Fourteenth); A-2(d) to Rule 24 Certificate dated February 24, 2000 in 70-8719 (Fifteenth); A-2(a) to Rule 24 Certificate dated February 9, 2001 in 70-9757 (Sixteenth); A-2(b) to Rule 24 Certificate dated October 31, 2002 in 70-9757 (Seventeenth); A-2(c) to Rule 24 Certificate dated December 2, 2002 in 70-9757 (Eighteenth); A-2(d) to Rule 24 Certificate dated February 6, 2003 in 70-9757 (Nineteenth); A-2(e) to Rule 24 Certificate dated April 4, 2003 in 70-9757 (Twentieth); A-2(f) to Rule 24 Certificate dated June 6, 2003 in 70-9757 (Twenty-first); A-3(a) to Rule 24 Certificate dated April 8, 2004 in 70-10157 (Twenty-second); A-3(b) to Rule 24 Certificate dated April 29, 2004 in 70-10157 (Twenty-third); A-3(c) to Rule 24 Certificate dated October 4, 2004 in 70-10157 (Twenty-fourth); A-3(d) to Rule 24 Certificate dated January 27, 2006 in 70-10157 (Twenty-fifth); and 4(b) to Form 10-Q for the quarter ended June 30, 2009 in 1-31508 (Twenty-sixth); 4(b) to Form 10-Q for the quarter ended March 31, 2010 in 1-31508 (Twenty-seventh); 4.38 to Form 8-K dated April 15, 2011 in 1-31508 (Twenty-eighth); 4.38 to Form 8-K dated May 13, 2011 in 1-31508 (Twenty-ninth); and 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth)). |
| (g) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by fourteensixteen Supplemental Indentures (A-2(c) to Rule 24 Certificate in 70-7350 (Mortgage); A-5(b) to Rule 24 Certificate in 70-7350 (First); A-4(b) to Rule 24 Certificate in 70-7448 (Second); 4(f)4 to Form 10-K for the year ended December 31, 1992 in 0-5807 (Third); 4(a) to Form 10-Q for the quarter ended September 30, 1993 in 0-5807 (Fourth); 4(a) to Form 8-K dated April 26, 1995 in 0-5807 (Fifth); 4(a) to Form 8-K dated March 22, 1996 in 0-5807 (Sixth); 4(b) to Form 10-Q for the quarter ended June 30, 1998 in 0-5807 (Seventh); 4(d) to Form 10-Q for the quarter ended June 30, 2000 in 0-5807 (Eighth); C-5(a) to Form U5S for the year ended December 31, 2000 (Ninth); 4(b) to Form 10-Q for the quarter ended September 30, 2002 in 0-5807 (Tenth); 4(k) to Form 10-Q for the quarter ended June 30, 2003 in 0-5807 (Eleventh); 4(a) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Twelfth); 4(b) to Form 10-Q for the quarter ended September 30, 2004 in 0-5807 (Thirteenth); and 4(e) to Form 10-Q for the quarter ended June 30, 2005 in 0-5807 (Fourteenth); 4.02 to Form 8-K dated November 23, 2010 in 0-5807 (Fifteenth); and 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth)). |
| (h) 1 -- | Credit Agreement ($200,000,000)150,000,000), dated as of August 2, 2007,March 9, 2012, among Entergy Gulf States,Texas, Inc., as borrower, the Banks named therein (Citibank, N.A., ABN AMRO Bank N.V., Barclays Bank PLC, BNP Paribas, Calyon New York Branch, Credit Suisse (Cayman Islands Branch), J. P. MorganJPMorgan Chase Bank, N.A., KeyBankWells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., Union Bank, N.A., Barclays Bank PLC, Goldman Sachs Bank USA, KeyBank National Association, Morgan Stanley Bank, The Bank of New York,N.A., The Royal Bank of Scotland plc, and WachoviaBNP Paribas, The Bank of New York Mellon, CoBank, ACB, Deutsche Bank AG New York Branch, Regions Bank, Sumitomo Mitsui Banking Corporation, U.S. Bank National Association)Association, SunTrust Bank, and National Cooperative Services Corporation), Citibank, N.A., as Administrative Agent and LC Issuing Bank, (10(c)JPMorgan Chase Bank, N.A., Wells Fargo Bank, National Association, Mizuho Corporate Bank, Ltd., The Bank of Nova Scotia, The Bank of Tokyo-Mitsubishi UFJ, Ltd., and Union Bank, N.A., as LC Issuing Banks, and the other LC Issuing Banks from time to time parties thereto (4.5 to Form 10-Q for the quarter ended June 30, 20078-K filed March 14, 2012 in 1-11299)1-34360). |
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| (h) 2 -- | Assumption Agreement, dated as of May 30, 2008, among Entergy Texas, Inc., Entergy Gulf States Louisiana, L.L.C. and Citibank, N.A., as administrative agent (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 0-53134). |
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| (h) 3 -- | Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)2 to Form 10-K for the year ended December 31, 2008 in 0-53134). |
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| (h) 4 -- | Officer'sOfficer’s Certificate No. 1-B-1 dated January 27, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(h)3 to Form 10-K for the year ended December 31, 2008 in 0-53134). |
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| (h) 5 -- | Officer'sOfficer’s Certificate No. 2-B-2 dated May 14, 2009, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2009 in 1-34360). |
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| (h) 6 -- | Officer’s Certificate No. 3-B-3 dated May 18, 2010, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4(a) to Form 10-Q for the quarter ended June 30, 2010 in 1-34360). |
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| (h) 7 -- | Officer’s Certificate No. 5-B-4 dated September 7, 2011, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas, Inc. and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated September 13, 2011 in 1-34360). |
| (a) 1 -- | Agreement, dated April 23, 1982, among certain System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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| (a) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-11299). |
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| (a) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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| (a) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080). |
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| (a) 5 -- | Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
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| (a) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
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*(a) 7 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(a)7 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
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| (a) 8 -- | Availability Agreement, dated June 21, 1974, among System Energy and certain other System companies (B to Rule 24 Certificate dated June 24, 1974 in 70-5399). |
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| (a) 9 -- | First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399). |
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| (a) 10 -- | Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592). |
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| (a) 11 -- | Third Amendment to Availability Agreement, dated as of June 28, 1984 (B-13(a) to Rule 24 Certificate dated July 6, 1984 in 70-6985). |
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| (a) 12 -- | Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
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| (a) 13 -- | Eighteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
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(a) 14 -- | Nineteenth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (C-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
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(a) 15 -- | Twenty-sixth Assignment of Availability Agreement, Consent and Agreement, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946). |
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(a) 16 -- | Twenty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946). |
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(a) 17 -- | Twenty-ninth Assignment of Availability Agreement, Consent and Agreement, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey as Trustees (B-2(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946). |
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(a) 18 -- | Thirtieth Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
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(a) 19 -- | Thirty-first Assignment of Availability Agreement, Consent and Agreement, dated as of August 1, 1996, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-2(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
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(a) 20 -- | Thirty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2002, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, The Bank of New York and Douglas J. MacInnes (B-2(a)(1) to Rule 24 Certificate dated October 4, 2001 in 70-9753). |
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(a) 21 -- | Amendment to the Thirty-fourth Assignment of Availability Agreement, Consent and Agreement, dated as of December 15, 2005 (B-5(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324). |
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(a) 22 -- | Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 22, 2003, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and Union Bank of California, N.A (10(a)25 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
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(a) 2314 -- | First Amendment to Thirty-fifth Assignment of Availability Agreement, Consent and Agreement, dated as of December 17, 2004 (10(a)24 to Form 10-K for the year ended December 31, 2004 in 1-11299). |
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*(a) 2415 -- | Thirty-sixthThirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2007,2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans, and The Bank of New York and Douglas J. MacInnes,Mellon, as trustees (10(a)24 to Form 10-K for the year ended December 31, 2007 in 1-11299).successor trustee. |
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(a) 2516 -- | Capital Funds Agreement, dated June 21, 1974, between Entergy Corporation and System Energy (C to Rule 24 Certificate dated June 24, 1974 in 70-5399). |
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(a) 2617 -- | First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
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(a) 27 -- | Eighteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-2 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
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(a) 28 -- | Nineteenth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 1986, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (D-3 to Rule 24 Certificate dated October 1, 1986 in 70-7272). |
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(a) 29 -- | Twenty-sixth Supplementary Capital Funds Agreement and Assignment, dated as of October 1, 1992, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(c) to Rule 24 Certificate dated November 2, 1992 in 70-7946). |
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(a) 30 -- | Twenty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1993, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(d) to Rule 24 Certificate dated May 4, 1993 in 70-7946). |
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(a) 31 -- | Twenty-ninth Supplementary Capital Funds Agreement and Assignment, dated as of April 1, 1994, with United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(f) to Rule 24 Certificate dated May 6, 1994 in 70-7946). |
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(a) 32 -- | Thirtieth Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(a) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
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(a) 33 -- | Thirty-first Supplementary Capital Funds Agreement and Assignment, dated as of August 1, 1996, among Entergy Corporation, System Energy and United States Trust Company of New York and Gerard F. Ganey, as Trustees (B-3(b) to Rule 24 Certificate dated August 8, 1996 in 70-8511). |
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(a) 34 -- | Thirty-fourth Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2002, among Entergy Corporation, System Energy, The Bank of New York and Douglas J. MacInnes (B-3(a)(1) to Rule 24 Certificate dated October 4, 2002 in 70-9753). |
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(a) 3518 -- | Thirty-fifth Supplementary Capital Funds Agreement and Assignment, dated as of December 22, 2003, among Entergy Corporation, System Energy, and Union Bank of California, N.A (10(a)38 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
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*(a) 3619 -- | Thirty-sixthThirty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2007,2012, among Entergy Corporation, System Energy, and The Bank of New York and Douglas J. MacInnes,Mellon, as Trustees (10(a)36 to Form 10-K for the year ended December 31, 2007 in 1-11299).successor trustee. |
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(a) 3720 -- | First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, Deposit Guaranty National Bank, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7026). |
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(a) 3821 -- | First Amendment to Supplementary Capital Funds Agreements and Assignments, dated as of June 1, 1989, by and between Entergy Corporation, System Energy, United States Trust Company of New York and Gerard F. Ganey (C to Rule 24 Certificate dated June 8, 1989 in 70-7123). |
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(a) 3922 -- | First Amendment to Supplementary Capital Funds Agreement and Assignment, dated as of June 1, 1989, by and between Entergy Corporation, System Energy and Chemical Bank (C to Rule 24 Certificate dated June 8, 1989 in 70-7561). |
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(a) 4023 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
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(a) 4124 -- | Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337). |
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(a) 4225 -- | Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
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(a) 4326 -- | Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
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(a) 4427 -- | Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
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(a) 4528 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
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(a) 4629 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
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(a) 4730 -- | Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-3517). |
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(a) 4831 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
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(a) 4932 -- | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
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(a) 5033 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(a) 5134 -- | Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
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(a) 5235 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
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(a) 5336 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
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(a) 5437 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
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(a) 5538 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
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*(a) 5639 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement.Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
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(a) 5740 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-11299). |
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| (a) 41 -- | Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(a) 5842 -- | Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
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(a) 5943 -- | Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70- 7757). |
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(a) 6044 -- | Loan Agreement between Entergy Operations and Entergy Corporation, dated as of September 20, 1990 (B-12(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
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(a) 6145 -- | Loan Agreement between Entergy Corporation and Entergy Systems and Service, Inc., dated as of December 29, 1992 (A-4(b) to Rule 24 Certificate in 70-7947). |
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+(a) 62 -- | Executive Financial Counseling Program of Entergy Corporation and Subsidiaries (10(a)64 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
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+(a) 63 -- | Amended and Restated Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 1, 2003 (10(b) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). |
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+(a) 64 -- | Equity Ownership Plan of Entergy Corporation and Subsidiaries (A-4(a) to Rule 24 Certificate dated May 24, 1991 in 70-7831). |
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+(a) 65 -- | Amendment No. 1 to the Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(a)71 to Form 10-K for the year ended December 31, 1992 in 1-3517). |
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+(a) 6646 -- | 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections On or After January 1, 2007) (Appendix B to Entergy Corporation's definitive proxy statement for its annual meeting of stockholders heldCorporation’s Definitive Proxy Statement filed on May 12,March 24, 2006 in 1-11299). |
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| +(a) 47 -- | First Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective October 26, 2006 (10(a)50 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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+(a) 6748 -- | Second Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective January 1, 2009 (10(a)51 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 49 -- | Third Amendment of the 2007 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries effective December 30, 2010 (10(a)52 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 50 -- | Amended and Restated 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Effective for Grants and Elections After February 13, 2003) (10(a) to Form 10-Q for the quarter ended March 31, 2003 in 1-11299). |
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+(a) 6851 -- | First Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2005 (10(a)54 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| +(a) 52 -- | Second Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective October 26, 2006 (10(a)55 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 53 -- | Third Amendment of the 1998 Equity Ownership Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)56 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 54 -- | 2011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 24, 2011 in 1-11299). |
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| +(a) 55 -- | Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 20002009 (10(a)7057 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
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+(a) 6956 -- | First Amendment effective December 28, 2001, toof the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)7158 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
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+(a) 7057 -- | Second Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)57 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
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| +(a) 58 -- | Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 20002009 (10(a)7259 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
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+(a) 7159 -- | First Amendment effective December 28, 2001, toof the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)7360 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
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+(a) 7260 -- | Second Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)60 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
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| +(a) 61 -- | Executive Disability Plan of Entergy Corporation and Subsidiaries (10(a)74 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
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+(a) 7362 -- | Amended and Restated Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, dated June 10, 2003 (10(d)as amended and restated effective January 1, 2009 (10(a)62 to Form 10-Q10-K for the quarteryear ended June 30, 2003December 31, 2010 in 1-11299). |
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+(a) 7463 -- | First Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)63 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 64 -- | Second Amendment of the Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)64 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
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| +(a) 65 -- | Equity Awards Plan of Entergy Corporation and Subsidiaries, effective as of August 31, 2000 (10(a)77 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| |
+(a) 7566 -- | Amendment, effective December 7, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(a)78 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| | |
+(a) 7667 -- | Amendment, effective December 10, 2001, to the Equity Awards Plan of Entergy Corporation and Subsidiaries (10(b) to Form 10-Q for the quarter ended March 31, 2002 in 1-11299). |
| | |
*+(a) 7768 -- | System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009.2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| | |
*+(a) 78--69-- | First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010. |
| |
+(a) 79 -- | System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective March 8, 2004 (10(e) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| |
+(a) 80 -- | First Amendment of the System Executive Continuity Plan II of Entergy Corporation and Subsidiaries, effective December 29, 20042010 (10(a)78 to Form 10-K for the year ended December 31, 20042009 in 1-11299). |
| | |
+(a) 8170 -- | Second Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)69 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
| +(a) 71 -- | Third Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)71 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
| +(a) 72 -- | Post-Retirement Plan of Entergy Corporation and Subsidiaries, as amended effective January 1, 2000 (10(a)80 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| | |
+(a) 8273 -- | Amendment, effective December 28, 2001, to the Post-Retirement Plan of Entergy Corporation and Subsidiaries (10(a)81 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| | |
+(a) 8374 -- | Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 20002009 (10(a)8274 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
| | |
+(a) 8475 -- | First Amendment effective December 28, 2001, toof the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)8375 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
| |
| +(a) 76 -- | Second Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)76 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| | |
+(a) 8577 -- | Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective JanuaryJune 1, 20092012 (10(a) to Form 10-Q for the quarter ended JuneSeptember 30, 20082012 in 1-11299). |
| | |
+(a) 8678 -- | Executive Income Security Plan of Gulf States Utilities Company, as amended effective March 1, 1991 (10(a)86 to Form 10-K for the year ended December 31, 2001 in 1-11299). |
| | |
+(a) 8779 -- | System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 20002009 (10(a)8778 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
| | |
+(a) 8880 -- | First Amendment effective December 28, 2001, toof the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)8879 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
| +(a) 81 -- | Second Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)81 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| | |
+(a) 8982 -- | Retention Agreement effective October 27, 2000 between J. Wayne Leonard and Entergy Corporation (10(a)81 to Form 10-K for the year ended December 31, 2000 in 1-11299). |
| | |
+(a) 9083 -- | Amendment to Retention Agreement effective March 8, 2004 between J. Wayne Leonard and Entergy Corporation (10(c) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| | |
+(a) 9184 -- | Amendment to Retention Agreement effective December 30, 2005 between J. Wayne Leonard and Entergy Corporation (10(a)91 to Form 10-K for the year ended December 31, 2005 in 1-11299). |
| | |
*+(a) 9285 -- | Amendment to Retention Agreement effective December 17,January 1, 2009 between J. Wayne Leonard and Entergy Corporation. |
| |
*+(a) 93- | Restricted Unit Agreement between J. Wayne Leonard and Entergy Corporation. |
| |
+(a) 94-- | Employment Agreement effective August 7, 2001 between Curt L. Hebert and Entergy Corporation (10(a)9783 to Form 10-K for the year ended December 31, 20012010 in 1-11299). |
| | |
| +(a) 86 -- | Amendment to Retention Agreement effective January 1, 2010 between J. Wayne Leonard and Entergy Corporation (10(a)92 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
| +(a) 87 -- | Amendment to Retention Agreement effective December 30, 2010 between J. Wayne Leonard and Entergy Corporation (10(a)85 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
(a) 95--88 -- | Agreement of Limited Partnership of Entergy-Koch, LP among EKLP, LLC, EK Holding I, LLC, EK Holding II, LLC and Koch Energy, Inc. dated January 31, 2001 (10(a)94 to Form 10-K/A for the year ended December 31, 2000 in 1-11299). |
| | |
+(a) 96-- | Employment Agreement effective April 15, 2003 between Robert D. Sloan and Entergy Services (10(c) to Form 10-Q for the quarter ended June 30, 2003 in 1-11299). |
| |
+(a) 9789 -- | Employment Agreement effective November 24, 2003 between Mark T. Savoff and Entergy Services (10(a)99 to Form 10-K for the year ended December 31, 2003 in 1-11299). |
| | |
+(a) 9890 -- | Employment Agreement effective February 9, 1999 between Leo P. Denault and Entergy Services (10(a) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| | |
+(a) 9991 -- | Amendment to Employment Agreement effective March 5, 2004 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| | |
+(a) 10092 -- | Retention Agreement effective August 3, 2006 between Leo P. Denault and Entergy Corporation (10(b) to Form 10-Q for the quarter ended June 30, 2006 in 1-11299). |
| | |
*+(a) 93 -- | Amendment to Retention Agreement effective January 1, 2009 between Leo P. Denault and Entergy Corporation (10(a)93 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
| +(a) 94 -- | Amendment to Retention Agreement effective January 1, 2010 between Leo P. Denault and Entergy Corporation (10(a)101 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
| +(a) 95 -- | Amendment to Retention Agreement effective December 16, 200930, 2010 between Leo P. Denault and Entergy Corporation.Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| | |
+(a) 10296 -- | Shareholder Approval of Future Severance Agreements Policy, effective March 8, 2004 (10(f) to Form 10-Q for the quarter ended March 31, 2004 in 1-11299). |
| |
(a) 103 -- | Consulting Agreement effective May 4, 2004 between Hintz & Associates, LLC and Entergy Services, Inc. (10(d) to Form 10-Q for the quarter ended June 30, 2004 in 1-11299). |
| |
+(a) 104 -- | Form of Stock Option Grant Agreement Letter, as of December 31, 2004 (99.1 to Form 8-K dated January 26, 2005 in 1-11299). |
| |
+(a) 105 -- | Form of Long Term Incentive Plan Performance Unit Grant Letter, as of December 31, 2004 (99.2 to Form 8-K dated January 26, 2005 in 1-11299). |
| |
+(a) 10697 -- | Entergy Corporation Outside Director Stock Program Established under the 20072011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation and Subsidiaries (Amended and Restated effective January 1, 2009) (10(b) to Form 10-Q for the quarter ended June 30, 20082011 in 1-11299). |
| | |
+(a) 10798 -- | First Amendment to Entergy Corporation Outside Director Stock Program Established under the 20072011 Equity Ownership and Long Term Cash Incentive Plan of Entergy Corporation Subsidiaries (10(a)105(10(b) to Form 10-K10-Q for the yearquarter ended December 31, 2008September 30, 2012 in 1-11299). |
| | |
+(a) 108 -- | Rescission Agreement effective July 26, 2007 between Richard J. Smith and Entergy Services, Inc. (10(d) to Form 10-Q for the quarter ended June 30, 2007 in 1-11299). |
| |
(a) 10999 -- | Entergy Nuclear Retention Plan, as amended and restated January 1, 2007 (10(a)107 to Form 10-K for the year ended December 31, 2007 in 1-11299). |
| | |
+(a) 110 -- | Form of Stock Option Grant Agreement Letter (10(a)108 to Form 10-K for the year ended December 31, 2007 in 1-11299). |
| |
+(a) 111100 -- | Restricted Unit Agreement between Leo P. Denault and Entergy Corporation (10(a) to Form 10-Q for the quarter ended March 31, 2008 in 1-11299). |
| | |
| +(a) 101 -- | Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2010 (Annex A to Entergy Corporation’s Definitive Proxy Statement filed on March 17, 2010 in 1-11299). |
| |
| +(a) 102 -- | First Amendment of the Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries, effective January 27, 2011 (10(a)106 to Form 10-K for the year ended December 31, 2011 in 1-11299). |
| |
*+(a) 112103-- | Form of Stock Option Grant Letter. |
| |
| *+(a)104-- | Form of Long Term Incentive Program Performance Unit Grant Letter. |
| |
| *+(a)105-- | Form of Restricted Stock Grant Letter. |
| |
| (a) 106 -- | RetentionEmployee Matters Agreement, effectivedated as of December 16, 20094, 2011, among Entergy Corporation, Mid South TransCo LLC and ITC Holdings Corp. (10.1 to Form 8-K filed December 6, 2011 in 1-11299). |
| |
| *+(a)107-- | Restricted Unit Agreement between Richard J. SmithJoseph F. Domino and Entergy Corporation. |
(b) 1 through (b) 178 -- See 10(a)8 through 10(a)2415 above. |
| |
(b) 189 through (b) 3215 -- See 10(a)2516 through 10(a)3922 above. |
| |
(b) 3316 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
(b) 3417 -- | Joint Construction, Acquisition and Ownership Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B-1(a) in 70-6337), as amended by Amendment No. 1, dated as of May 1, 1980 (B-1(c) in 70-6337) and Amendment No. 2, dated as of October 31, 1980 (1 to Rule 24 Certificate dated October 30, 1981 in 70-6337). |
| | |
(b) 3518 -- | Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
| |
(b) 3619 -- | Amended and Restated Installment Sale Agreement, dated as of February 15, 1996, between System Energy and Claiborne County, Mississippi (B-6(a) to Rule 24 Certificate dated March 4, 1996 in 70-8511). |
| | |
(b) 3720 -- | Loan Agreement, dated as of October 15, 1998, between System Energy and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated November 12, 1998 in 70-8511). |
| | |
(b) 3821 -- | Loan Agreement, dated as of May 15, 1999, between System Energy and Mississippi Business Finance Corporation (B-6(c) to Rule 24 Certificate dated June 8, 1999 in 70-8511). |
| | |
(b) 3922 -- | Facility Lease No. 1, dated as of December 1, 1988, between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (1) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-3(d) to Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-3(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| | |
(b) 4023 -- | Facility Lease No. 2, dated as of December 1, 1988 between Meridian Trust Company and Stephen M. Carta (Stephen J. Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561), as supplemented by Lease Supplement No. 1 dated as of April 1, 1989 (B-22(b) (2) to Rule 24 Certificate dated April 21, 1989 in 70-7561), Lease Supplement No. 2 dated as of January 1, 1994 (B-4(d) Rule 24 Certificate dated January 31, 1994 in 70-8215), and Lease Supplement No. 3 dated as of May 1, 2004 (B-4(d) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| | |
(b) 4124 -- | Assignment, Assumption and Further Agreement No. 1, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
| | |
(b) 4225 -- | Assignment, Assumption and Further Agreement No. 2, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(2) to Rule 24 Certificate dated January 9, 1989 in 70-7561). |
| |
(b) 4326 -- | Collateral Trust Indenture, dated as of May 1, 2004, among GG1C Funding Corporation, System Energy, and Deutsche Bank Trust Company Americas, as Trustee (A-3(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182), as supplemented by Supplemental Indenture No. 1 dated May 1, 2004, (A-4(a) to Rule 24 Certificate dated June 4, 2004 in 70-10182). |
| | |
(b) 4427 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
| | |
(b) 4528 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
| | |
(b) 4629 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
(b) 4730 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| |
(b) 4831 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| | |
(b) 4932 -- | Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(b) to Rule 24 Certificate dated March 3, 1989 in 70-7604). |
| | |
(b) 5033 -- | System Energy'sEnergy’s Consent, dated January 31, 1995, pursuant to Fuel Lease, dated as of February 24, 1989, between River Fuel Funding Company #3, Inc. and System Energy (B-1(c) to Rule 24 Certificate dated February 13, 1995 in 70-7604). |
| | |
(b) 5134 -- | Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| | |
(b) 5235 -- | Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| | |
(b) 5336 -- | Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399). |
| | |
(b) 5437 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| | |
(b) 5538 -- | First Amendment, dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| | |
(b) 5639 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
| | |
(b) 5740 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| |
(b) 5841 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| | |
(b) 5942 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)1-9067). |
| | |
(b) 6043 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-9067). |
| |
| (b) 44 -- | Service Agreement with Entergy Services, dated as of July 16, 1974, as amended (10(b)43 to Form 10-K for the year ended December 31, 1988 in 1-9067). |
| | |
(b) 6145 -- | Amendment, dated January 1, 2004, to Service Agreement with Entergy Services (10(b)57 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| |
*(b) 6246 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(b)46 to Form 10-K for the year ended December 31, 2011 in 1-9067). |
| | |
(b) 6347 -- | Operating Agreement between Entergy Operations and System Energy, dated as of June 6, 1990 (B-3(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
| | |
(b) 6448 -- | Guarantee Agreement between Entergy Corporation and System Energy, dated as of September 20, 1990 (B-3(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
| | |
(b) 6549 -- | Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003, among System Energy Resources, Inc., Union Bank of California, N.A., as administrating bank and funding bank, Keybank National Association, as syndication agent, Banc One Capital Markets, Inc., as documentation agent, and the Banks named therein, as Participating Banks (10(b)63 to Form 10-K for the year ended December 31, 2003 in 1-9067). |
| | |
(b) 6650 -- | Amendment to Letter of Credit and Reimbursement Agreement, dated as of December 22, 2003 (10(b)62 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| | |
(b) 6751 -- | First Amendment and Consent, dated as of May 3, 2004, to Letter of Credit and Reimbursement Agreement (10(b)63 to Form 10-K for the year ended December 31, 2004 in 1-9067). |
| | |
(b) 6852 -- | Second Amendment and Consent, dated as of December 17, 2004, to Letter of Credit and Reimbursement Agreement (99 to Form 8-K dated December 22, 2004 in 1-9067). |
| | |
*(b) 6953 -- | Third Amendment and Consent, dated as of May 14, 2009, to Letter of Credit and Reimbursement Agreement.Agreement (10(b)69 to Form 10-K for the year ended December 31, 2009 in 1-9067). |
| |
| (b) 54 -- | Fourth Amendment and Consent, dated as of April 15, 2010, to Letter of Credit and Reimbursement Agreement (10(a) to Form 10-Q for the quarter ended March 31, 2010 in 1-9067). |
| |
| *(b) 55 -- | Fifth Amendment and Consent, dated as of November 15, 2012, to Letter of Credit and Reimbursement Agreement. |
| (c) 1 -- | Agreement, dated April 23, 1982, among Entergy Arkansas and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a) 1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
| (c) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-10764). |
| | |
| (c) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| | |
| (c) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080). |
| | |
| (c) 5 -- | Amendment, dated April 27, 1984, to Service Agreement, with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
| |
| (c) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(a)12 to Form 10-K for the year ended December 31, 2002 in 1-10764). |
| | |
*(c) 7 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(c)7 to Form 10-K for the year ended December 31, 2011 in 1-10764). |
| | |
(c) 8 through (c) 2415 -- See 10(a)8 through 10(a)2415 above. |
| |
(c) 2516 -- | Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467). |
| | |
(c) 2617 -- | Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080). |
| | |
(c) 2718 -- | Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080). |
| | |
(c) 2819 -- | Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080). |
| | |
(c) 2920 -- | Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080). |
| | |
(c) 3021 -- | Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080). |
| | |
(c) 3122 -- | Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080). |
| | |
(c) 3223 -- | Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080). |
| | |
(c) 3324 -- | Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175). |
| |
(c) 3425 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233). |
| | |
(c) 3526 -- | Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080). |
| | |
(c) 3627 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233). |
| | |
(c) 3728 -- | Contract, dated May 28, 1943, Amendment to Contract, dated July 21, 1949, and Supplement to Amendment to Contract, dated December 30, 1949, between Entergy Arkansas and McKamie Gas Cleaning Company; Agreements, dated as of September 30, 1965, between Entergy Arkansas and former stockholders of McKamie Gas Cleaning Company; and Letter Agreement, dated June 22, 1966, by Humble Oil & Refining Company accepted by Entergy Arkansas on June 24, 1966 (5(k)7 in 2-41080). |
| |
(c) 3829 -- | Fuel Lease, dated as of December 22, 1988, between River Fuel Trust #1 and Entergy Arkansas (B-1(b) to Rule 24 Certificate in 70-7571). |
| | |
(c) 3930 -- | White Bluff Operating Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-2(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009). |
| | |
(c) 4031 -- | White Bluff Ownership Agreement, dated June 27, 1977, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas (B-1(a) to Rule 24 Certificate dated June 30, 1977 in 70-6009). |
| | |
(c) 4132 -- | Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235). |
| | |
(c) 4233 -- | Transmission Agreement, dated August 2, 1977, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)3 in 2-60233). |
| | |
(c) 4334 -- | Power Coordination, Interchange and Transmission Service Agreement, dated as of June 27, 1977, between Arkansas Electric Cooperative Corporation and Entergy Arkansas (5(r)4 in 2-60233). |
| | |
(c) 4435 -- | Independence Steam Electric Station Operating Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)6 in 2-66235). |
| | |
(c) 4536 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| | |
(c) 4637 -- | Independence Steam Electric Station Ownership Agreement, dated July 31, 1979, among Entergy Arkansas and Arkansas Electric Cooperative Corporation and City Water and Light Plant of the City of Jonesboro, Arkansas and City of Conway, Arkansas (5(r)7 in 2-66235). |
| | |
(c) 4738 -- | Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235). |
| |
(c) 4839 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| | |
(c) 4940 -- | Owner'sOwner’s Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| | |
(c) 5041 -- | Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 1-10764). |
| | |
(c) 5142 -- | Power Coordination, Interchange and Transmission Service Agreement, dated as of July 31, 1979, between Entergy Arkansas and City Water and Light Plant of the City of Jonesboro, Arkansas (5(r)8 in 2-66235). |
| | |
(c) 5243 -- | Power Coordination, Interchange and Transmission Agreement, dated as of June 29, 1979, between City of Conway, Arkansas and Entergy Arkansas (5(r)9 in 2-66235). |
| |
(c) 5344 -- | Agreement, dated June 21, 1979, between Entergy Arkansas and Reeves E. Ritchie (10(b)90 to Form 10-K for the year ended December 31, 1980 in 1-10764). |
| | |
(c) 5445 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
(c) 5546 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
(c) 5647 -- | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| | |
(c) 5748 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| | |
(c) 5849 -- | Contract For Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated June 30, 1983, among the DOE, System Fuels and Entergy Arkansas (10(b)57 to Form 10-K for the year ended December 31, 1983 in 1-10764). |
| | |
(c) 5950 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| | |
(c) 6051 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| | |
(c) 6152 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
| | |
(c) 6253 -- | Third Amendment dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| |
(c) 6354 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| | |
(c) 6455 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)1-10764). |
| | |
(c) 6556 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 1-10764). |
| |
| (c) 57 -- | Assignment of Coal Supply Agreement, dated December 1, 1987, between System Fuels and Entergy Arkansas (B to Rule 24 letter filing dated November 10, 1987 in 70-5964). |
| |
(c) 6658 -- | Coal Supply Agreement, dated December 22, 1976, between System Fuels and Antelope Coal Company (B-1 in 70-5964), as amended by First Amendment (A to Rule 24 Certificate in 70-5964); Second Amendment (A to Rule 24 letter filing dated December 16, 1983 in 70-5964); and Third Amendment (A to Rule 24 letter filing dated November 10, 1987 in 70-5964). |
| | |
(c) 6759 -- | Operating Agreement between Entergy Operations and Entergy Arkansas, dated as of June 6, 1990 (B-1(b) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
| | |
(c) 6860 -- | Guaranty Agreement between Entergy Corporation and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
| | |
(c) 6961 -- | Agreement for Purchase and Sale of Independence Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-3(c) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
| | |
(c) 7062 -- | Agreement for Purchase and Sale of Ritchie Unit 2 between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-4(d) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
| | |
(c) 7163 -- | Ritchie Steam Electric Station Unit No. 2 Operating Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-5(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
| | |
(c) 7264 -- | Ritchie Steam Electric Station Unit No. 2 Ownership Agreement between Entergy Arkansas and Entergy Power, dated as of August 28, 1990 (B-6(a) to Rule 24 Certificate dated September 6, 1990 in 70-7684). |
| | |
(c) 7365 -- | Power Coordination, Interchange and Transmission Service Agreement between Entergy Power and Entergy Arkansas, dated as of August 28, 1990 (10(c)71 to Form 10-K for the year ended December 31, 1990 in 1-10764). |
| | |
(c) 7466 -- | Loan Agreement, dated June 15, 1993,as of January 1, 2013, between Entergy Arkansas and Independence Country, Arkansas (B-1(a) to Rule 24 Certificate dated July 9, 1993 in 70-8171). |
| |
(c) 75 -- | Loan Agreement dated June 15, 1994, between Entergy Arkansas and Jefferson County, Arkansas (B-1(a)and Entergy Arkansas relating to Rule 24 Certificate dated June 30, 1994Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 70-8405)1-10764). |
| |
(c) 7667 -- | Loan Agreement, dated June 15, 1994,as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas and Pope County,relating to Revenue Bonds (Entergy Arkansas, (B-1(b) to Rule 24 Certificate in 70-8405). |
| |
(c) 77 -- | Loan Agreement dated November 15, 1995, between Entergy Arkansas and Pope County, Arkansas (10(c)96Inc. Project) Series 2013 (4(d) to Form 10-K for the year ended December 31, 1995 in 1-10764). |
| |
(c) 78 -- | Loan Agreement dated December 1, 1997, between Entergy Arkansas and Jefferson County, Arkansas (10(c)100 to Form 10-K for the year ended December 31, 1997 in 1-10764). |
| |
(c) 79 -- | Refunding Agreement, dated December 1, 2001, between Entergy Arkansas and Pope Country, Arkansas (10(c)81 to Form 10-K for the year ended December 31, 20018-K filed January 9, 2013 in 1-10764). |
| Entergy Gulf States Louisiana |
(d) 1 -- | Guaranty Agreement, dated August 1, 1992, between Entergy Gulf States, Inc. and Hibernia National Bank, relating to Pollution Control Revenue Refunding Bonds of the Industrial Development Board of the Parish of Calcasieu, Inc. (Louisiana) (10-1 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
(d) 2 -- | Guaranty Agreement, dated January 1, 1993, between Entergy Gulf States, Inc. and Hancock Bank of Louisiana, relating to Pollution Control Revenue Refunding Bonds of the Parish of Pointe Coupee (Louisiana) (10-2 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
(d) 3 -- | Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031). |
| | |
(d) 42 -- | Joint Ownership Participation and Operating Agreement regarding River Bend Unit 1 Nuclear Plant, dated August 20, 1979, between Entergy Gulf States, Inc., Cajun, and SRG&T; Power Interconnection Agreement with Cajun, dated June 26, 1978, and approved by the REA on August 16, 1979, between Entergy Gulf States, Inc. and Cajun; and Letter Agreement regarding CEPCO buybacks, dated August 28, 1979, between Entergy Gulf States, Inc. and Cajun (2, 3, and 4, respectively, to Form 8-K dated September 7, 1979 in 1-27031). |
| |
(d) 53 -- | Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031). |
| | |
(d) 64 -- | Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031). |
| | |
(d) 75 -- | Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031). |
| | |
(d) 86 -- | Agreements between Southern Company and Entergy Gulf States, Inc., dated February 25, 1982, which cover the construction of a 140-mile transmission line to connect the two systems, purchase of power and use of transmission facilities (10-31 to Form 10-K for the year ended December 31, 1981 in 1-27031). |
| | |
(d) 97 -- | Transmission Facilities Agreement between Entergy Gulf States, Inc. and Mississippi Power Company, dated February 28, 1982, and Amendment, dated May 12, 1982 (A-2-c to Form 10-Q for the quarter ended March 31, 1982 in 1-27031) and Amendment, dated December 6, 1983 (10-43 to Form 10-K for the year ended December 31, 1983 in 1-27031). |
| | |
(d) 108 -- | First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031). |
| | |
+(d) 119 -- | Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| |
+(d) 1210 -- | Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| | |
+(d) 1311 -- | Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| | |
+(d) 1412 -- | Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| | |
+(d) 1513 -- | Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
(d) 1614 -- | Nuclear Fuel Lease Agreement between Entergy Gulf States, Inc. and River Bend Fuel Services, Inc. to lease the fuel for River Bend Unit 1, dated February 7, 1989 (10-64 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
| | |
(d) 1715 -- | Trust and Investment Management Agreement between Entergy Gulf States, Inc. and Morgan Guaranty and Trust Company of New York (the “Decommissioning Trust Agreement"Agreement”) with respect to decommissioning funds authorized to be collected by Entergy Gulf States, Inc., dated March 15, 1989 (10-66 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
| | |
(d) 1816 -- | Amendment No. 2 dated November 1, 1995 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)31 to Form 10-K for the year ended December 31, 1995 in 1-27031). |
| | |
(d) 1917 -- | Amendment No. 3 dated March 5, 1998 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)23 to Form 10-K for the year ended December 31, 2004 in 1-27031). |
| | |
(d) 2018 -- | Amendment No. 4 dated December 17, 2003 between Entergy Gulf States, Inc. and Mellon Bank to Decommissioning Trust Agreement (10(d)24 to Form 10-K for the year ended December 31, 2004 in 1-27031). |
| | |
(d) 2119 -- | Amendment No. 5 dated December 31, 2007 between Entergy Gulf States Louisiana, L.L.C. and Mellon Bank. N.A. to Decommissioning Trust Agreement (10(d)21 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
(d) 2220 -- | Partnership Agreement by and among Conoco Inc., and Entergy Gulf States, Inc., CITGO Petroleum Corporation and Vista Chemical Company, dated April 28, 1988 (10-67 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
| | |
+(d) 2321 -- | Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| |
+(d) 2422 -- | Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| | |
+(d) 2523 -- | Gulf States Utilities Board of Directors'Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| | |
(d) 2624 -- | Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| | |
(d) 2725 -- | Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| | |
(d) 2826 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)0-20371). |
| (d) 27 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-20371). |
| | |
(d) 29 -- | Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Parish of Iberville, State of Louisiana (B-3(a) to Rule 24 Certificate dated May 29, 1998 in 70-8721). |
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(d) 30 -- | Amendment No. 1 effective as of October 31, 2007, to Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Parish of Iberville, State of Louisiana (10(d)29 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| |
(d) 31 -- | Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Industrial Development Board of the Parish of Calcasieu, Inc. (B-3(b) to Rule 24 Certificate dated January 29, 1999 in 70-8721). |
| |
(d) 32 -- | Amendment No. 1 effective as of October 31, 2007, to Refunding Agreement dated as of May 1, 1998 between Entergy Gulf States, Inc. and Industrial Development Board of the Parish of Calcasieu, Inc (10(d)31 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| |
(d) 33 -- | Refunding Agreement (Series 1999-A) dated as of September 1, 1999 between Entergy Gulf States, Inc. and Parish of West Feliciana, State of Louisiana (B-3(c) to Rule 24 Certificate dated October 8, 1999 in 70-8721). |
| |
(d) 34 -- | Amendment No. 1 effective as of October 31, 2007, to Refunding Agreement (Series 1999-A) dated as of September 1, 1999 between Entergy Gulf States, Inc. and Parish of West Feliciana, State of Louisiana (10(d)33 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| |
(d) 35 -- | Refunding Agreement (Series 1999-B) dated as of September 1, 1999 between Entergy Gulf States, Inc. and Parish of West Feliciana, State of Louisiana (B-3(d) to Rule 24 Certificate dated October 8, 1999 in 70-8721). |
| |
(d) 36 -- | Amendment No. 1 effective as of October 31, 2007, to Refunding Agreement (Series 1999-B) dated as of September 1, 1999 between Entergy Gulf States, Inc. and Parish of West Feliciana, State of Louisiana (10(d)35 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| |
(d) 37 -- | Debt Assumption Agreement, dated as of December 31, 2007, between Entergy Texas and Entergy Gulf States Louisiana (4(i) to Form 8-K15D5 dated January 7, 2008 in 333-148557). |
| |
(d) 38 -- | Instrument of Correction dated March 20, 2008, to Debt Assumption Agreement, dated as of December 31, 2007, between Entergy Gulf States Louisiana and Entergy Texas (4(a) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
| |
(d) 39 -- | Mortgage and Security Agreement, dated as of December 31, 2007 (4(ii) to Form 8-K15D5 dated January 7, 2008 in 333-148557). |
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(d) 40 -- | Act of Correction to Mortgage and Security Agreement, dated March 20, 2008, between Entergy Gulf States Louisiana and Entergy Texas (4(b) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
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(d) 41 -- | Mortgage, Deed of Trust and Security Agreement, dated as of December 31, 2007 (4(iii) - 4(iii)(r) to Form 8-K15D5 dated January 7, 2008 in 333-148557). |
| |
(d) 42 -- | First Amendment to Mortgage, Deed of Trust and Security Agreement, dated March 20, 2008, among Entergy Gulf States Louisiana, Entergy Texas, and Mark G. Otts, as Trustee (4(c) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
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(d) 4328 -- | Operating Agreement dated as of January 1, 2008, between Entergy Operations, Inc. and Entergy Gulf States Louisiana (10(d)39 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
(d) 4429 -- | Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Gulf States Louisiana (10(d)40 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
*(d) 4530 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(d)30 to Form 10-K for the year ended December 31, 2011 in 0-20371). |
| | |
(d) 4631 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
(d) 4732 -- | Decommissioning Trust Agreement, dated as of December 22, 1997, by and between Cajun Electric Power Cooperative, Inc. and Mellon Bank, N.A. with respect to decommissioning funds authorized to be collected by Cajun Electric Power Cooperative, Inc. and related Settlement Term Sheet (10(d)42 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
(d) 4833 -- | First Amendment to Decommissioning Trust Agreement, dated as of December 23, 2003, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States, Inc., and the Rural Utilities Services of the United States Department of Agriculture (10(d)43 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| | |
(d) 4934 -- | Second Amendment to Decommissioning Trust Agreement, dated December 31, 2007, by and among Cajun Electric Power Cooperative, Inc., Mellon Bank, N.A., Entergy Gulf States Louisiana, L.L.C., and the Rural Utilities Services of the United States Department of Agriculture (10(d)44 to Form 10-K for the year ended December 31, 2007 in 333-148557). |
| |
(d) 5035 -- | Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 29, 200822, 2010 (10(a) to Form 10-Q for the quarter ended SeptemberJune 30, 2008)2010). |
| |
| (d) 36 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010A (4(b) to Form 8-K filed October 12, 2010 in 0-20371). |
| |
| (d) 37 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Gulf States Louisiana, L.L.C. relating to Revenue Bonds (Entergy Gulf States Louisiana, L.L.C. Project) Series 2010B (4(e) to Form 8-K filed October 12, 2010 in 0-20371). |
| (e) 1 -- | Agreement, dated April 23, 1982, among Entergy Louisiana and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982, in 1-3517). |
| |
| (e) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-32718). |
| | |
| (e) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| | |
| (e) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-42523). |
| | |
| (e) 5 -- | Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
| | |
| (e) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(e)12 to Form 10-K for the year ended December 31, 2002 in 1-8474). |
| | |
*(e) 7 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(e)7 to Form 10-K for the year ended December 31, 2011 in 1-32718). |
| | |
(e) 8 through (e) 2415 -- See 10(a)8 through 10(a)2415 above. |
| | |
(e) 2516 -- | Fuel Lease, dated as of January 31, 1989, between River Fuel Company #2, Inc., and Entergy Louisiana (B-1(b) to Rule 24 Certificate in 70-7580). |
| | |
(e) 2617 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
(e) 2718 -- | Compromise and Settlement Agreement, dated June 4, 1982, between Texaco, Inc. and Entergy Louisiana (28(a) to Form 8-K dated June 4, 1982 in 1-8474). |
| | |
(e) 2819 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
(e) 2920 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| |
(e) 3021 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| | |
(e) 3122 -- | Contract for Disposal of Spent Nuclear Fuel and/or High-Level Radioactive Waste, dated February 2, 1984, among DOE, System Fuels and Entergy Louisiana (10(d)33 to Form 10-K for the year ended December 31, 1984 in 1-8474). |
| | |
(e) 32--23-- | Operating Agreement between Entergy Operations and Entergy Louisiana, dated as of June 6, 1990 (B-2(c) to Rule 24 Certificate dated June 15, 1990 in 70-7679). |
| | |
(e) 3324 -- | Guarantee Agreement between Entergy Corporation and Entergy Louisiana, dated as of September 20, 1990 (B-2(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
| | |
(e) 3425 -- | Refunding Agreement (Series 1999-A), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(a) to Rule 24 Certificate dated July 6, 1999 in 70-9141). |
| |
(e) 35 -- | Amendment No. 1 to Refunding Agreement (Series 1999-A), dated as of December 15, 2005 (B-8(i) to Rule 24 Certificate dated January 10, 2006 in 70-10324). |
| |
(e) 36 -- | Refunding Agreement (Series 1999-B), dated as of June 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-6(b) to Rule 24 Certificate dated July 6, 1999 in 70-9141). |
| |
(e) 37 -- | Amendment No. 1 to Refunding Agreement (Series 1999-B), dated as of December 16, 2005 (B-8(ii) to Rule 24 Certificate dated January 10, 2006 in 70-10324). |
| |
(e) 38 -- | Refunding Agreement (Series 1999-C), dated as of October 1, 1999, between Entergy Louisiana and Parish of St. Charles, State of Louisiana (B-11(a) to Rule 24 Certificate dated October 15, 1999 in 70-9141). |
| |
(e) 39 -- | Amendment No. 1 to Refunding Agreement (Series 1999-C), dated as of December 15, 2005 (B-8(iii) to Rule 24 Certificate dated January 10, 2006 in 70-10324). |
| |
(e) 40 -- | Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 29, 200822, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010). |
| (e) 26 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-32718). |
| |
| (e) 27 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2008)2010 in 1-32718). |
| |
| (e) 28 -- | Loan Agreement, dated as of October 1, 2010, between the Louisiana Public Facilities Authority and Entergy Louisiana, LLC relating to Revenue Bonds (Entergy Louisiana, LLC Project) Series 2010 (4(b) to Form 8-K filed October 12, 2010 in 1-32718). |
| (f) 1 -- | Agreement dated April 23, 1982, among Entergy Mississippi and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
| (f) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 1-31508). |
| | |
| (f) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| | |
| (f) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). |
| | |
| (f) 5 -- | Amendment, dated April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
| | |
| (f) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(f)12 to Form 10-K for the year ended December 31, 2002 in 1-31508). |
| | |
*(f) 7 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(f)7 to Form 10-K for the year ended December 31, 2011 in 1-31508). |
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(f) 8 through (f) 2415 -- See 10(a)8 through 10(a)2415 above. |
| | |
(f) 2516 -- | Loan Agreement, dated as of September 1, 2004, between Entergy Mississippi and Mississippi Business Finance Corporation (B-3(a) to Rule 24 Certificate dated October 4, 2004 in 70-10157). |
| | |
(f) 2617 -- | Refunding Agreement, dated as of May 1, 1999, between Entergy Mississippi and Independence County, Arkansas (B-6(a) to Rule 24 Certificate dated June 8, 1999 in 70-8719). |
| | |
(f) 2718 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B-3(a) in 70-6337). |
| | |
(f) 2819 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Operating Agreement (10(c)51 to Form 10-K for the year ended December 31, 1984 in 0-375). |
| | |
(f) 2920 -- | Amendment, dated December 4, 1984, to the Independence Steam Electric Station Ownership Agreement (10(c)54 to Form 10-K for the year ended December 31, 1984 in 0-375). |
| |
(f) 3021 -- | Owners Agreement, dated November 28, 1984, among Entergy Arkansas, Entergy Mississippi and other co-owners of the Independence Station (10(c)55 to Form 10-K for the year ended December 31, 1984 in 0-375). |
| | |
(f) 3122 -- | Consent, Agreement and Assumption, dated December 4, 1984, among Entergy Arkansas, Entergy Mississippi, other co-owners of the Independence Station and United States Trust Company of New York, as Trustee (10(c)56 to Form 10-K for the year ended December 31, 1984 in 0-375). |
| | |
(f) 3223 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
+(f) 3324 -- | Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320). |
| | |
(f) 3425 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
(f) 3526 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| | |
(f) 3627 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| | |
(f) 3728 -- | Sales Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (D to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| | |
(f) 3829 -- | Service Agreement, dated as of June 21, 1974, between System Energy and Entergy Mississippi (E to Rule 24 Certificate dated June 26, 1974 in 70-5399). |
| | |
(f) 3930 -- | Partial Termination Agreement, dated as of December 1, 1986, between System Energy and Entergy Mississippi (A-2 to Rule 24 Certificate dated January 8, 1987 in 70-5399). |
| | |
(f) 4031 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| |
(f) 4132 -- | First Amendment dated January 1, 1990 to the Middle South Utilities Inc. and Subsidiary Companies Intercompany Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| | |
(f) 4233 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
| | |
(f) 4334 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| | |
(f) 4435 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| |
(f) 4536 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)1-31508). |
| | |
+(f) 4637 -- | EmploymentSixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement effective July 24, 2003 between Carolyn C. Shanks and Entergy Mississippi (10(f)48(10(a) to Form 10-K10-Q for the yearquarter ended December 31, 2003September 30, 2010 in 1-31508). |
| | |
(f) 4738 -- | Purchase and Sale Agreement by and between Central Mississippi Generating Company, LLC and Entergy Mississippi, Inc., dated as of March 16, 2005 (10(b) to Form 10-Q for the quarter ended March 31, 2005 in 1-31508). |
| (g) 1 -- | Agreement, dated April 23, 1982, among Entergy New Orleans and certain other System companies, relating to System Planning and Development and Intra-System Transactions (10(a)1 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
| (g) 2 -- | Second Amended and Restated Entergy System Agency Agreement, dated as of January 1, 2008 (10(a)2 to Form 10-K for the year ended December 31, 2007 in 0-5807). |
| | |
| (g) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| | |
| (g) 4 -- | Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523). |
| | |
| (g) 5 -- | Amendment, dated as of April 27, 1984, to Service Agreement with Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 1984 in 1-3517). |
| | |
| (g) 6 -- | Amendment, dated January 1, 2000, to Service Agreement with Entergy Services (10(g)12 to Form 10-K for the year ended December 31, 2002 in 0-5807). |
| | |
*(g) 7 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(g)7 to Form 10-K for the year ended December 31, 2011 in 0-5807). |
| |
(g) 8 through (g) 2415 -- See 10(a)8 through 10(a)2415 above. |
| | |
(g) 2516 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
(g) 2617 -- | Unit Power Sales Agreement, dated as of June 10, 1982, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (10(a)39 to Form 10-K for the year ended December 31, 1982 in 1-3517). |
| | |
(g) 2718 -- | First Amendment to the Unit Power Sales Agreement, dated as of June 28, 1984, between System Energy and Entergy Arkansas, Entergy Louisiana, Entergy Mississippi and Entergy New Orleans (19 to Form 10-Q for the quarter ended September 30, 1984 in 1-3517). |
| | |
(g) 2819 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(g) 2920 -- | Transfer Agreement, dated as of June 28, 1983, among the City of New Orleans, Entergy New Orleans and Regional Transit Authority (2(a) to Form 8-K dated June 24, 1983 in 1-1319). |
| | |
(g) 3021 -- | Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement, dated April 28, 1988 (D-1 to Form U5S for the year ended December 31, 1987). |
| | |
(g) 3122 -- | First Amendment, dated January 1, 1990, to the Middle South Utilities, Inc. and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-2 to Form U5S for the year ended December 31, 1989). |
| | |
(g) 3223 -- | Second Amendment dated January 1, 1992, to the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3 to Form U5S for the year ended December 31, 1992). |
| | |
(g) 3324 -- | Third Amendment dated January 1, 1994 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| | |
(g) 3425 -- | Fourth Amendment dated April 1, 1997 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| | |
(g) 3526 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)0-5807). |
| | |
(g) 3627 -- | Sixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a) to Form 10-Q for the quarter ended September 30, 2010 in 0-5807). |
| |
| (g) 28 -- | Chapter 11 Plan of Reorganization of Entergy New Orleans, Inc., as modified, dated May 2, 2007, confirmed by bankruptcy court order dated May 7, 2007 (2(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
| (h) 1 -- | Agreement effective February 1, 1964, between Sabine River Authority, State of Louisiana, and Sabine River Authority of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Company, Inc., and Louisiana Power & Light Company, as supplemented (B to Form 8-K dated May 6, 1964, A to Form 8-K dated October 5, 1967, A to Form 8-K dated May 5, 1969, and A to Form 8-K dated December 1, 1969 in 1-27031). |
| | |
| (h) 2 -- | Ground Lease, dated August 15, 1980, between Statmont Associates Limited Partnership (Statmont) and Entergy Gulf States, Inc., as amended (3 to Form 8-K dated August 19, 1980 and A-3-b to Form 10-Q for the quarter ended September 30, 1983 in 1-27031). |
| | |
| (h) 3 -- | Lease and Sublease Agreement, dated August 15, 1980, between Statmont and Entergy Gulf States, Inc., as amended (4 to Form 8-K dated August 19, 1980 and A-3-c to Form 10-Q for the quarter ended September 30, 1983 in 1-27031). |
| | |
| (h) 4 -- | Lease Agreement, dated September 18, 1980, between BLC Corporation and Entergy Gulf States, Inc. (1 to Form 8-K dated October 6, 1980 in 1-27031). |
| |
| (h) 5 -- | Joint Ownership Participation and Operating Agreement for Big Cajun, between Entergy Gulf States, Inc., Cajun Electric Power Cooperative, Inc., and Sam Rayburn G&T, Inc, dated November 14, 1980 (6 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 1, dated December 12, 1980 (7 to Form 8-K dated January 29, 1981 in 1-27031); Amendment No. 2, dated December 29, 1980 (8 to Form 8-K dated January 29, 1981 in 1-27031). |
| |
| (h) 6 -- | Agreement of Joint Ownership Participation between SRMPA, SRG&T and Entergy Gulf States, Inc., dated June 6, 1980, for Nelson Station, Coal Unit #6, as amended (8 to Form 8-K dated June 11, 1980, A-2-b to Form 10-Q for the quarter ended June 30, 1982; and 10-1 to Form 8-K dated February 19, 1988 in 1-27031). |
| | |
| (h) 7 -- | First Amended Power Sales Agreement, dated December 1, 1985 between Sabine River Authority, State of Louisiana, and Sabine River Authority, State of Texas, and Entergy Gulf States, Inc., Central Louisiana Electric Co., Inc., and Louisiana Power and Light Company (10-72 to Form 10-K for the year ended December 31, 1985 in 1-27031). |
| | |
| +(h) 8 -- | Deferred Compensation Plan for Directors of Entergy Gulf States, Inc. and Varibus Corporation, as amended January 8, 1987, and effective January 1, 1987 (10-77 to Form 10-K for the year ended December 31, 1986 in 1-27031). Amendment dated December 4, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| | |
| +(h) 9 -- | Trust Agreement for Deferred Payments to be made by Entergy Gulf States, Inc. pursuant to the Executive Income Security Plan, by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective November 1, 1986 (10-78 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| | |
| +(h) 10 -- | Trust Agreement for Deferred Installments under Entergy Gulf States, Inc. Management Incentive Compensation Plan and Administrative Guidelines by and between Entergy Gulf States, Inc. and Bankers Trust Company, effective June 1, 1986 (10-79 to Form 10-K for the year ended December 31, 1986 in 1-27031). |
| | |
| +(h) 11 -- | Nonqualified Deferred Compensation Plan for Officers, Nonemployee Directors and Designated Key Employees, effective December 1, 1985, as amended, continued and completely restated effective as of March 1, 1991 (10-3 to Amendment No. 8 in Registration No. 2-76551). |
| |
| +(h) 12 -- | Trust Agreement for Entergy Gulf States, Inc. Nonqualified Directors and Designated Key Employees by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective July 1, 1991 (10-4 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| | |
| (h) 13 -- | Lease Agreement, dated as of June 29, 1987, among GSG&T, Inc., and Entergy Gulf States, Inc. related to the leaseback of the Lewis Creek generating station (10-83 to Form 10-K for the year ended December 31, 1988 in 1-27031). |
| | |
| +(h) 14 -- | Gulf States Utilities Company Executive Continuity Plan, dated January 18, 1991 (10-6 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| | |
| +(h) 15 -- | Trust Agreement for Entergy Gulf States, Inc. Executive Continuity Plan, by and between Entergy Gulf States, Inc. and First City Bank, Texas-Beaumont, N.A. (now Texas Commerce Bank), effective May 20, 1991 (10-5 to Form 10-K for the year ended December 31, 1992 in 1-27031). |
| |
| +(h) 16 -- | Gulf States Utilities Board of Directors'Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
| | |
| (h) 17 -- | Third Amendment, dated January 1, 1994, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-3(a) to Form U5S for the year ended December 31, 1993). |
| | |
| (h) 18 -- | Fourth Amendment, dated April 1, 1997, to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (D-5 to Form U5S for the year ended December 31, 1996). |
| | |
| (h) 19 -- | Fifth Amendment dated November 20, 2009 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement (10(a)56 to Form 10-K for the year ended December 31, 2009 in 1-11299)1-34360). |
| | |
| (h) 20 -- | Debt AssumptionSixth Amendment dated October 11, 2010 to Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement dated as of December 31, 2007, between Entergy Texas and Entergy Gulf States Louisiana (4(i)(10(a) to Form 8-K dated January 7, 200810-Q for the quarter ended September 30, 2010 in 333-148557)1-34360). |
| | |
(h) 21 -- | Instrument of Correction dated March 20, 2008, to Debt Assumption Agreement, dated as of December 31, 2007, between Entergy Texas and Entergy Gulf States Louisiana (4(a) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
| |
(h) 22 -- | Mortgage and Security Agreement, dated as of December 31, 2007 (4(ii) to Form 8-K dated January 7, 2008 in 333-148557). |
| |
(h) 23 -- | Act of Correction to Mortgage and Security Agreement, dated March 20, 2008, between Entergy Texas and Entergy Gulf States Louisiana (4(b) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
| |
(h) 24 -- | Mortgage, Deed of Trust and Security Agreement, dated as of December 31, 2007 (4(iii) - 4(iii)(r) to Form 8-K dated January 7, 2008 in 333-148557). |
| |
(h) 25 -- | First Amendment to Mortgage, Deed of Trust and Security Agreement, dated March 20, 2008, among Entergy Texas, Entergy Gulf States, and Mark G. Otts, as Trustee (4(c) to Form 10-Q for the quarter ended March 31, 2008 in 333-148557). |
| |
(h) 26 -- | Service Agreement dated as of January 1, 2008, between Entergy Services, Inc. and Entergy Texas (10(h)25 to Form 10-K for the year ended December 31, 2008 in 3-53134). |
| | |
*(h) 2722 -- | Amendment, dated JuneJanuary 1, 2009,2011, to Service Agreement with Entergy Services.Services (10(h)22 to Form 10-K for the year ended December 31, 2011 in 1-34360). |
| (12) Statement Re Computation of Ratios |
| *(a) | Entergy Arkansas'Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| | |
| *(b) | Entergy Gulf States Louisiana'sLouisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined. |
| | |
| *(c) | Entergy Louisiana'sLouisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined. |
| |
| *(d) | Entergy Mississippi'sMississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| | |
| *(e) | Entergy New Orleans'Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
| | |
| *(f) | Entergy Texas'Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
| | |
| *(g) | System Energy'sEnergy’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
| *(21) Subsidiaries of the Registrants |
| (23) Consents of Experts and Counsel |
| *(a) | The consent of Deloitte & Touche LLP is contained herein at page 487.511. |
| (31) Rule 13a-14(a)/15d-14(a) Certifications |
| *(a) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
| | |
| *(b) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
| | |
| *(c) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
| | |
| *(d) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
| | |
| *(e) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana. |
| | |
| *(f) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Gulf States Louisiana. |
| | |
| *(g) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
| | |
| *(h) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
| | |
| *(i) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
| | |
| *(j) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
| | |
| *(k) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
| | |
| *(l) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
| | |
| *(m) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
| | |
| *(n) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
| | |
| *(o) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
| | |
| *(p) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
| (32) Section 1350 Certifications |
| *(a) | Section 1350 Certification for Entergy Corporation. |
| | |
| *(b) | Section 1350 Certification for Entergy Corporation. |
| | |
| *(c) | Section 1350 Certification for Entergy Arkansas. |
| | |
| *(d) | Section 1350 Certification for Entergy Arkansas. |
| | |
| *(e) | Section 1350 Certification for Entergy Gulf States Louisiana. |
| | |
| *(f) | Section 1350 Certification for Entergy Gulf States Louisiana. |
| | |
| *(g) | Section 1350 Certification for Entergy Louisiana. |
| | |
| *(h) | Section 1350 Certification for Entergy Louisiana. |
| |
| *(i) | Section 1350 Certification for Entergy Mississippi. |
| | |
| *(j) | Section 1350 Certification for Entergy Mississippi. |
| | |
| *(k) | Section 1350 Certification for Entergy New Orleans. |
| | |
| *(l) | Section 1350 Certification for Entergy New Orleans. |
| | |
| *(m) | Section 1350 Certification for Entergy Texas. |
| | |
| *(n) | Section 1350 Certification for Entergy Texas. |
| | |
| *(o) | Section 1350 Certification for System Energy. |
| | |
| *(p) | Section 1350 Certification for System Energy. |
| *INS - | XBRL Instance Document. |
| | |
| *SCH - | XBRL Taxonomy Extension Schema Document. |
| | |
| *CAL - | XBRL Taxonomy Extension Calculation Linkbase Document. |
| | |
| *DEF - | XBRL Taxonomy Extension Definition Linkbase Document. |
| | |
| *LAB - | XBRL Taxonomy Extension Label Linkbase Document. |
| | |
| *PRE - | XBRL Taxonomy Extension Presentation Linkbase Document. |
| | + Management contracts or compensatory plans or arrangements. |
