UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
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| X | ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| | For the Fiscal Year Ended December 31, 20152016 |
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| | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
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| | For the transition period from ____________ to ____________ |
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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 | | 1-35747
| ENTERGY NEW ORLEANS, INC. (a Louisiana corporation) 1600 Perdido Street New Orleans, Louisiana 70112 Telephone (504) 670-3700 72-0273040 |
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| 1-10764 | ENTERGY ARKANSAS, INC. (an Arkansas corporation) 425 West Capitol Avenue Little Rock, Arkansas 72201 Telephone (501) 377-4000 71-0005900 | | 1-34360
| ENTERGY TEXAS, INC. (a Texas corporation) 9425 Pinecroft10055 Grogans Mill Road
The Woodlands, TX 77380 Telephone (409) 981-2000 61-1435798 |
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1-32718
| ENTERGY LOUISIANA, LLC (a Texas limited liability company) 4809 Jefferson Highway Jefferson, Louisiana 70121 Telephone (504) 576-4000 47-4469646 | | 1-09067
| SYSTEM ENERGY RESOURCES, INC. (an Arkansas corporation) Echelon One
1340 Echelon Parkway Jackson, Mississippi 39213 Telephone (601) 368-5000 72-0752777 |
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1-31508
| ENTERGY MISSISSIPPI, INC. (a Mississippi corporation) 308 East Pearl Street Jackson, Mississippi 39201 Telephone (601) 368-5000 64-0205830 | | | |
Securities registered pursuant to Section 12(b) of the Act:
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| Registrant | Title of Class | Name of Each Exchange on Which Registered |
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| Entergy Corporation | Common Stock, $0.01 Par Value – 178,492,025 179,394,698 shares outstanding at January 29, 2016 31, 2017 | New York Stock Exchange, Inc. Chicago Stock Exchange, Inc. |
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| Entergy Arkansas, Inc. | Mortgage Bonds, 5.75% Series due November 2040 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 4.90% Series due December 2052 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.75% Series due June 2063 | New York Stock Exchange, Inc. |
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Entergy Louisiana, LLC | Mortgage Bonds, 6.0%4.875% Series due March 2040September 2066 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 5.875% Series due June 2041 | New York Stock Exchange, Inc. |
| Entergy Louisiana, LLC | Mortgage Bonds, 5.25% Series due July 2052 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.70% Series due June 2063 | New York Stock Exchange, Inc. |
| | Mortgage Bonds, 4.875% Series due September 2066 | New York Stock Exchange, Inc. |
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| Entergy Mississippi, Inc. | Mortgage Bonds, 6.0%4.90% Series due November 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 2051October 2066 | New York Stock Exchange, Inc. |
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| Entergy New Orleans, Inc. | Mortgage Bonds, 5.0% Series due December 2052 | New York Stock Exchange, Inc. |
| Mortgage Bonds, 5.50% Series due April 2066 | New York Stock Exchange, Inc. |
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| Entergy Texas, Inc. | Mortgage Bonds, 5.625% Series due June 2064 | New York Stock Exchange, Inc. |
Securities registered pursuant to Section 12(g) of the Act:
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| Registrant | Title of Class |
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| Entergy Arkansas, Inc. | Preferred Stock, Cumulative, $100 Par Value |
| Preferred Stock, Cumulative, $0.01 Par Value |
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| Entergy Mississippi, Inc. | Preferred Stock, Cumulative, $100 Par Value |
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| Entergy New Orleans, Inc. | Preferred Stock, Cumulative, $100 Par Value |
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| 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.
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| | Yes | | No |
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| Entergy Corporation | ü | | |
| Entergy Arkansas, Inc. | | | ü |
| Entergy Louisiana, LLC | ü | | |
| Entergy Mississippi, Inc. | | | ü |
| Entergy New Orleans, Inc. | | | ü |
| Entergy Texas, Inc. | | | ü |
| System Energy Resources, Inc. | | | ü |
Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.
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| | Yes | | No |
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| Entergy Corporation | | | ü |
| Entergy Arkansas, Inc. | | | ü |
| Entergy Louisiana, LLC | | | ü |
| Entergy Mississippi, Inc. | | | ü |
| Entergy New Orleans, Inc. | | | ü |
| Entergy Texas, Inc. | | | ü |
| System Energy Resources, Inc. | | | ü |
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 the registrants 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 registrant was required to submit and post such files). Yes þ 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’ 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. [ü]
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 filer,” “large accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Securities Exchange Act of 1934.
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| | Large accelerated filer | | Accelerated filer | | Non-accelerated filer | | Smaller reporting company |
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| Entergy Corporation | ü | | | | | | |
| Entergy Arkansas, Inc. | | | | | ü | | |
| Entergy Louisiana, LLC | | | | | ü | | |
| Entergy Mississippi, Inc. | | | | | ü | | |
| Entergy New Orleans, Inc. | | | | | ü | | |
| Entergy Texas, Inc. | | | | | ü | | |
| System Energy Resources, Inc. | | | | | ü | | |
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 2015,2016 was $12.7$14.6 billion based on the reported last sale price of $70.50$81.35 per share for such stock on the New York Stock Exchange on June 30, 2015.2016. 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 direct and indirect holder of the common membership interests of Entergy Utility Holdings Company, LLC, which is the sole holder of the common membership interests of Entergy Louisiana, LLC.
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 6, 2016,5, 2017, are incorporated by reference into Part III hereof.
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TABLE OF CONTENTS
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| | SEC Form 10-K Reference Number | Page Number |
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| Part II. Item 7. | |
| Part II. Item 6. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part I. Item 1. | |
| Part I. Item 1. | |
| Part I. Item 1. | |
| Part I. Item 1. | |
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| Part I. Item 1A. | |
| Unresolved Staff Comments | Part I. Item 1B. | None |
| Entergy Arkansas, Inc. and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Louisiana, LLC and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Mississippi, Inc. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy New Orleans, Inc. and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Entergy Texas, Inc. and Subsidiaries | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
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| System Energy Resources, Inc. | | |
| Part II. Item 7. | |
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| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 8. | |
| Part II. Item 6. | |
| Part I. Item 2. | |
| Part I. Item 3. | |
| Part I. Item 4. | |
| Part I. and Part III. Item 10. | |
| Part II. Item 5. | |
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| Part II. Item 6. | |
| Part II. Item 7. | |
| Part II. Item 7A. | |
| Part II. Item 8. | |
| Part II. Item 9. | |
| Part II. Item 9A. | |
| Part II. Item 9A. | |
| Part III. Item 10. | |
| Part III. Item 11. | |
| Part III. Item 12. | |
| Part III. Item 13. | |
| Part III. Item 14. | |
| Part IV. Item 15. | |
| Part IV. Item 16. |
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This combined Form 10-K is separately filed by Entergy Corporation and its six “Registrant Subsidiaries”:Subsidiaries:” Entergy Arkansas, Inc., 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.
FORWARD-LOOKING INFORMATION
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” 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,” 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 (a) those factors discussed or incorporated by reference in Item 1A. Risk Factors, (b) those factors discussed or incorporated by reference in 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, Entergy’s utility supply plan, and recovery of fuel and purchased power costs;
the termination of Entergy Arkansas’s participation in the System Agreement, which occurred in December 2013, the termination of Entergy Mississippi’s participation in the System Agreement, which occurred in November 2015,long-term risks and the termination of Entergy Texas’s, Entergy New Orleans’s, and Entergy Louisiana’s participation in the System Agreement, which will occur on August 31, 2016, and will result inuncertainties associated with the termination of the System Agreement in its entirety pursuant2016, including the potential absence of federal authority to a settlement agreement approved by FERC in December 2015;resolve certain issues among the Utility operating companies and their retail regulators;
regulatory and operating challenges and uncertainties and economic risks associated with the Utility operating companies’ move toparticipation in MISO, which occurred in December 2013, including the effect of current or projected MISO market rules and market and system conditions in the MISO markets, the allocation of MISO system transmission upgrade costs, and the effect of planning decisions that MISO makes with respect to future transmission investments by the Utility operating companies;
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, and the application of more stringent transmission reliability requirements or market power criteria by the FERC;FERC or the U.S. Department of Justice;
changes in the regulation or regulatory oversight of Entergy’s nuclear generating facilities and nuclear materials and fuel, including with respect to the planned potential or actual shutdown of nuclear generating facilities owned or operated by Entergy Wholesale Commodities, 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 or other authorizations required of nuclear generating facilities and the effect of public and political opposition on these applications, regulatory proceedings, and litigation;
the performance of and deliverability of power from Entergy’s generation resources, including the capacity factors at its nuclear generating facilities;
the operation and maintenance of Entergy’s nuclear generating facilities require the commitment of substantial human and capital resources that can result in increased costs and capital expenditures;
Entergy’s ability to develop and execute on a point of view regarding future prices of electricity, natural gas, and other energy-related commodities;
prices for power generated by Entergy’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 Entergy Wholesale Commodities nuclear plants;
the prices and availability of fuel and power Entergy must purchase for its Utility customers, and Entergy’s ability to meet credit support requirements for fuel and power supply contracts;
FORWARD-LOOKING INFORMATION (Concluded)
volatility and changes in markets for electricity, natural gas, uranium, emissions allowances, and other energy-related commodities, and the effect of those changes on Entergy and its customers;
FORWARD-LOOKING INFORMATION (Concluded)
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;
changes in environmental tax, and other laws and regulations or associated litigation, including requirements for reduced emissions of sulfur dioxide, nitrogen oxide, greenhouse gases, mercury, thermal energy,particulate matter, heat, and other regulated air and water emissions, and changes in costs of compliance with environmental and other laws and regulations;
the effects of changes in federal, state or local laws and regulations, and other governmental actions or policies, including changes in monetary, fiscal, tax, environmental, or energy policies;
uncertainty regarding the establishment of interim or permanent sites for spent nuclear fuel and nuclear waste storage and disposal and the level of spent fuel and nuclear waste disposal fees charged by the U.S. government or other providers related to such sites;
variations in weather and the occurrence of hurricanes and other storms and disasters, including uncertainties associated with efforts to remediate the effects of hurricanes, ice storms, or other weather events and the recovery of costs associated with restoration, including accessing funded storm reserves, federal and local cost recovery mechanisms, securitization, and insurance;
effects of climate change;change, including the potential for increases in sea levels or coastal land and wetland loss;
changes in the quality and availability of water supplies and the related regulation of water use and diversion;
Entergy’s ability to manage its capital projects and operation and maintenance costs;
Entergy’s ability to purchase and sell assets at attractive prices and on other attractive terms;
the economic climate, and particularly economic conditions in Entergy’s Utility service area and the Northeast United States and events and circumstances that could influence economic conditions in those areas, including power prices, and the risk that anticipated load growth may not materialize;
the effects of Entergy’s strategies to reduce tax payments;
changes in the financial markets and regulatory requirements for the issuance of securities, particularly those affecting the availability ofas they affect access to capital and Entergy’s ability to refinance existing debt,securities, execute share repurchase programs, and fund investments and acquisitions;
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’ ratings criteria;
changes in inflation and interest rates;
the effect of litigation and government investigations or proceedings;
changes in technology, including with respect to new, developing, or alternative sources of generation;
the effects, including increased security costs, of threatened or actual terrorism, cyber-attacks or data security breaches, including increased security costs,natural or man-made electromagnetic pulses that affect transmission or generation infrastructure, accidents, and war or a catastrophic event such as a nuclear accident or a natural gas pipeline explosion;
Entergy’s ability to attract and retain talented management and directors;
changes in accounting standards and corporate governance;
declines in the market prices of marketable securities and resulting funding requirements and the effects on benefitbenefits costs for Entergy’s defined benefit pension and other postretirement benefit plans;
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, requirements for, or cost to decommission Entergy’s nuclear plant sites;sites and the implementation of decommissioning of such sites following shutdown;
the decision to cease merchant power generation at all Entergy Wholesale Commodities nuclear power plants by as early as 2021, including the implementation of the planned shutdown of Pilgrim, Palisades, Indian Point 2, and FitzPatrickIndian Point 3 and the related decommissioningplanned shutdown or sale of those plants and Vermont Yankee;FitzPatrick;
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,strategic transactions Entergy may undertake, including mergers, acquisitions, or divestiture plans,divestitures, regulatory or other limitations imposed as a result of a merger, acquisition, or divestiture,any such strategic transaction, and the success of the business following a merger, acquisition, or divestiture.any such strategic transaction.
DEFINITIONS
Certain abbreviations or acronyms used in the text and notes are defined below:
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| Abbreviation or Acronym | Term |
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| AFUDC | Allowance for Funds Used During Construction |
| ALJ | Administrative Law Judge |
| ANO 1 and 2 | Units 1 and 2 of Arkansas Nuclear One (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 |
City Council or Council | Council of the City of New Orleans, Louisiana |
| D. C. Circuit | U.S. Court of Appeals for the District of Columbia Circuit |
| DOE | United States Department of Energy |
| 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 Louisiana limited liability 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. Effective October 1, 2015, the business of Entergy Gulf States Louisiana was combined with Entergy Louisiana. |
| Entergy Louisiana | Entergy Louisiana, LLC, a Texas limited liability company formally created as part of the combination of Entergy Gulf States Louisiana and the company formerly known as Entergy Louisiana, LLC (Old Entergy Louisiana) into a single public utility company and the successor to Old Entergy Louisiana for financial reporting purposes. |
| Entergy Texas | Entergy Texas, Inc., a Texas corporation 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, operation, and decommissioning of nuclear power plants, the ownership of interests in non-nuclear power plants, and the sale of the electric power produced by its operating power plants to wholesale customers |
| EPA | United States Environmental Protection Agency |
| ERCOT | Electric Reliability Council of Texas |
| FASB | Financial Accounting Standards Board |
| FERC | Federal Energy Regulatory Commission |
| FitzPatrick | James A. FitzPatrick Nuclear Power Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
FTR | Financial transmission right |
| Grand Gulf | Unit No. 1 of Grand Gulf Nuclear Station (nuclear), 90% owned or leased by System Energy |
DEFINITIONS (Continued)
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| Abbreviation or Acronym | Term |
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| GWh | Gigawatt-hour(s), which equals one million kilowatt-hours |
| Independence | Independence Steam Electric Station (coal), owned 16% by Entergy Arkansas, 25% by Entergy Mississippi, and 7% by Entergy Power, LLC |
| Indian Point 2 | Unit 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 | Midcontinent Independent 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 kilowatts |
| 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 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 |
| NRC | Nuclear Regulatory Commission |
| NYPA | New York Power Authority |
| Palisades | Palisades Nuclear Plant (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| Parent & Other | The portions of Entergy not included in the Utility or Entergy Wholesale Commodities segments, primarily consisting of the activities of the parent company, Entergy Corporation |
| Pilgrim | Pilgrim Nuclear Power Station (nuclear), owned by an Entergy subsidiary in the Entergy Wholesale Commodities business segment |
| PPA | Purchased power agreement 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 |
| Registrant Subsidiaries | Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. |
DEFINITIONS (Concluded)
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| Abbreviation or Acronym | Term |
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Ritchie Unit 2 | Unit 2 of the R.E. Ritchie Steam Electric Generating Station (gas/oil) |
| River Bend | River Bend Station (nuclear), owned by Entergy Louisiana |
| RTO | Regional transmission organization |
| SEC | Securities and Exchange Commission |
SMEPA | South Mississippi Electric Power Association, which owns a 10% interest in Grand Gulf |
| 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. Entergy ArkansasThe agreement terminated its participation in the System Agreement effective December 18, 2013. Entergy Mississippi terminated its participation in the System Agreement effective November 7, 2015.August 2016. |
| System Energy | System Energy Resources, Inc. |
System Fuels | System Fuels, Inc. |
| TWh | Terawatt-hour(s), which equals one billion kilowatt-hours |
| 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’s share of Grand Gulf |
| Utility | Entergy’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 (prior to the completion of the business combination with Entergy 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, which ceased power production in December 2014 |
| Waterford 3 | Unit No. 3 (nuclear) of the Waterford Steam Electric 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 |
ENTERGY CORPORATION AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
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 operation of a small natural gas distribution business.
The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In October 2015, Entergy determined that it will close the Pilgrim plant no later than June 1, 2019 and the FitzPatrick plant at the end of its current fuel cycle, which is planned for January 27, 2017. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” below for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.
Following are the percentages of Entergy’s consolidated revenues and net income generated by its operating segments and the percentage of total assets held by them.
| | | | % of Revenue | | % of Net Income (Loss) | | % of Total Assets | % of Revenue | | % of Net Income (Loss) | | % of Total Assets |
| Segment | 2015 | 2014 | 2013 | | 2015 | 2014 | 2013 | | 2015 | 2014 | 2013 | 2016 | 2015 | 2014 | | 2016 | 2015 | 2014 | | 2016 | 2015 | 2014 |
| Utility | 82 |
| 78 |
| 80 |
| | 711 |
| 88 |
| 116 |
| | 86 |
| 82 |
| 82 |
| 83 |
| 82 |
| 78 |
| | 204 |
| 711 |
| 88 |
| | 89 |
| 86 |
| 82 |
|
| Entergy Wholesale Commodities | 18 |
| 22 |
| 20 |
| | (680 | ) | 31 |
| 6 |
| | 18 |
| 22 |
| 22 |
| 17 |
| 18 |
| 22 |
| | (265 | ) | (680 | ) | 31 |
| | 15 |
| 18 |
| 22 |
|
| Parent & Other | — |
| — |
| — |
| | (131 | ) | (19 | ) | (22 | ) | | (4 | ) | (4 | ) | (4 | ) | — |
| — |
| — |
| | (39 | ) | (131 | ) | (19 | ) | | (4 | ) | (4 | ) | (4 | ) |
See Note 13 to the financial statements for further financial information regarding Entergy’s business segments.
Net income (loss) for 2016 includes $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. Net income (loss) for 2015 includes $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 114 to the financial statements for further discussion of the impairment and related charges.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Results of Operations
20152016 Compared to 20142015
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 20152016 to 20142015 showing how much the line item increased or (decreased) in comparison to the prior period.
| | | | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy | Utility | | Entergy Wholesale Commodities | | Parent & Other (a) | | Entergy |
| | (In Thousands) | (In Thousands) |
| 2014 Consolidated Net Income (Loss) |
| $846,496 |
| |
| $294,521 |
| |
| ($180,760 | ) | |
| $960,257 |
| |
| 2015 Consolidated Net Income (Loss) | |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($205,593 | ) | |
| ($156,734 | ) |
| | | | | | | | | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 94,195 |
| | (558,060 | ) | | (1,885 | ) | | (465,750 | ) | 350,528 |
| | (123,791 | ) | | (33 | ) | | 226,704 |
|
| Other operation and maintenance | 166,812 |
| | (123,645 | ) | | 1,278 |
| | 44,445 |
| (83,265 | ) | | 15,269 |
| | 9,726 |
| | (58,270 | ) |
| Asset write-offs, impairments, and related charges | (3,553 | ) | | 1,928,707 |
| | — |
| | 1,925,154 |
| (68,672 | ) | | 799,403 |
| | — |
| | 730,731 |
|
| Taxes other than income taxes | 35,010 |
| | (20,196 | ) | | 2 |
| | 14,816 |
| (10,229 | ) | | (16,259 | ) | | (432 | ) | | (26,920 | ) |
| Depreciation and amortization | 57,076 |
| | (36,892 | ) | | (1,546 | ) | | 18,638 |
| 49,600 |
| | (39,180 | ) | | (509 | ) | | 9,911 |
|
| Gain on sale of business | — |
| | 154,037 |
| | — |
| | 154,037 |
| |
| Gain on sale of asset | | — |
| | (154,037 | ) | | — |
| | (154,037 | ) |
| Other income | (3,993 | ) | | (4,899 | ) | | (18,607 | ) | | (27,499 | ) | 15,153 |
| | 8,666 |
| | 4,281 |
| | 28,100 |
|
| Interest expense | 11,403 |
| | 10,142 |
| | (5,583 | ) | | 15,962 |
| 14,414 |
| | (3,930 | ) | | 12,417 |
| | 22,901 |
|
| Other expenses | 10,821 |
| | (19,533 | ) | | — |
| | (8,712 | ) | 19,589 |
| | (15,074 | ) | | — |
| | 4,515 |
|
| Income taxes | (455,387 | ) | | (787,327 | ) | | 10,190 |
| | (1,232,524 | ) | 407,627 |
| | (581,924 | ) | | (35 | ) | | (174,332 | ) |
| 2015 Consolidated Net Income (Loss) |
| $1,114,516 |
|
|
| ($1,065,657 | ) |
|
| ($205,593 | ) |
|
| ($156,734 | ) | |
| 2016 Consolidated Net Income (Loss) | |
| $1,151,133 |
| |
| ($1,493,124 | ) | |
| ($222,512 | ) | |
| ($564,503 | ) |
| |
| (a) | Parent & Other includes eliminations, which are primarily intersegment activity. |
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.
Results of operations for 2016 include $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. Results of operations for 2016 also include a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 3 to the financial statements for additional discussion of the income tax items. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Palisades plants and related assets to their fair values. See Note 114 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of an agreement with the LPSC.stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $5,829 |
|
| Retail electric price | 289 |
|
| Louisiana business combination customer credits | 107 |
|
| Volume/weather | 14 |
|
| Louisiana Act 55 financing savings obligation | (17 | ) |
| Other | (43 | ) |
| 2016 net revenue |
| $6,179 |
|
The retail electric price variance is primarily due to:
an increase in base rates at Entergy Arkansas, as approved by the APSC. The new rates were effective February 24, 2016 and began billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase is related to the purchase of Power Block 2 of the Union Power Station;
an increase in the purchased power and capacity acquisition cost recovery rider for Entergy New Orleans, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station;
an increase in formula rate plan revenues for Entergy Louisiana, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and 4 of the Union Power Station; and
an increase in revenues at Entergy Mississippi, as approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in revenues collected through the storm damage rider.
See Note 2 to the financial statements for further discussion of the rate proceedings. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
The Louisiana business combination customer credits variance is due to a regulatory liability of $107 million recorded by Entergy in October 2015 as a result of the Entergy Gulf States Louisiana and Entergy Louisiana business
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax). These costs are being amortized over a nine-year period beginning December 2015. See Note 2 to the financial statements for further discussion of the business combination and customer credits.
The volume/weather variance is primarily due to the effect of more favorable weather during the unbilled period and an increase in industrial usage, partially offset by the effect of less favorable weather on residential sales. The increase in industrial usage is primarily due to expansion projects, primarily in the chemicals industry, and increased demand from new customers, primarily in the industrial gases industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings results from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $1,666 |
|
| Nuclear realized price changes | (149 | ) |
| Rhode Island State Energy Center | (44 | ) |
| Nuclear volume | (36 | ) |
| FitzPatrick reimbursement agreement | 41 |
|
| Nuclear fuel expenses | 68 |
|
| Other | (4 | ) |
| 2016 net revenue |
| $1,542 |
|
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $124 million in 2016 primarily due to:
lower realized wholesale energy prices and lower capacity prices, although the average revenue per MWh shown in the table below for the nuclear fleet is slightly higher because it includes revenues from the FitzPatrick reimbursement agreement with Exelon, the amortization of the Palisades below-market PPA, and Vermont Yankee capacity revenue. The effect of the amortization of the Palisades below-market PPA and Vermont Yankee capacity revenue on the net revenue variance from 2015 to 2016 is minimal;
the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and
lower volume in the Entergy Wholesale Commodities nuclear fleet resulting from more refueling outage days in 2016 as compared to 2015 and larger exercise of resupply options in 2016 as compared to 2015. See “Nuclear
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Matters - Indian Point 2 Outage” below for discussion of the extended Indian Point 2 outage in the second quarter 2016.
The decrease was partially offset by:
an increase resulting from the reimbursement agreement with Exelon pursuant to which Exelon is reimbursing Entergy for specified out-of-pocket costs associated with preparing for the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Revenues received from Exelon under the reimbursement agreement are offset in nuclear fuel expenses and other operation and maintenance expenses and have no material effect on net income. See “Entergy Wholesale Commodities Exit from the Merchant Power Business - Planned Sale of FitzPatrick” below for further discussion of the reimbursement agreement; and
a decrease in nuclear fuel expenses primarily related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets. See Note 14 to the financial statements for discussion of the impairments.
Following are key performance measures for Entergy Wholesale Commodities for 2016 and 2015.
|
| | | |
| | 2016 | | 2015 |
| Owned capacity (MW) (a) | 4,800 | | 4,880 |
| GWh billed | 35,881 | | 39,745 |
| Average revenue per MWh | $51.55 | | $51.88 |
| | | | |
| Entergy Wholesale Commodities Nuclear Fleet | | | |
| Capacity factor | 87% | | 91% |
| GWh billed | 33,551 | | 35,859 |
| Average revenue per MWh | $51.90 | | $51.49 |
| Refueling Outage Days: | | | |
| FitzPatrick | — | | — |
| Indian Point 2 | 102 | | — |
| Indian Point 3 | — | | 23 |
| Palisades | — | | 32 |
| Pilgrim | — | | 34 |
| |
| (a) | The reduction in owned capacity is due to Entergy’s sale of its 50% membership interest in Top Deer Wind Ventures, LLC in November 2016. See Note 14 to the financial statements for discussion of the sale. |
Other Income Statement Items
Utility
Other operation and maintenance expenses decreased from $2,443 million for 2015 to $2,360 million for 2016 primarily due to:
a decrease of $78 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
the effects of recording final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $19 million of spent nuclear
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
fuel storage costs previously recorded as other operation and maintenance expense. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
the deferral in 2016 of $8 million of previously-incurred costs related to ANO post-Fukushima compliance and $10 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC in February 2016 as part of the Entergy Arkansas 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
a decrease of $13 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result of participation in energy efficiency programs.
The decrease was partially offset by an increase of $61 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor, and an overall higher scope of work done during plant outages in 2016 as compared to prior year.
The asset write-offs, impairments, and related charges variance is due to the following activity:
the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project was no longer probable of recovery; and
the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement.
See Note 2 to the financial statements for further discussion of the asset write-offs.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Union Power Station purchased in March 2016, partially offset by the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $11 million in 2016 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Other expenses increased primarily due to an increase in nuclear refueling outage expenses as a result of amortization of higher costs associated with refueling outages and increases in decommissioning expenses in 2016 primarily due to revised decommissioning cost studies in 2015 for Grand Gulf and Waterford 3. See Note 9 to the financial statements for further discussion of the revised decommissioning cost studies.
Entergy Wholesale Commodities
Other operation and maintenance expenses increased from $899 million for 2015 to $915 million for 2016 primarily due to:
an increase of $60 million in severance and retention costs related to the planned shutdown or sale of the Pilgrim and FitzPatrick plants. See “Entergy Wholesale Commodities Exit From the Merchant Power Business” below and Note 14 to the financial statements for discussion of the decisions to cease operations of the plants;
$41 million associated with preparing to refuel FitzPatrick in January 2017. Exelon reimbursed Entergy for these costs in accordance with the reimbursement agreement discussed in “Entergy Wholesale Commodities Exit From the Merchant Power Business - Planned Sale of FitzPatrick” below; and
an increase of $26 million in costs related to Pilgrim’s response to a planned NRC enhanced inspection as a result of the NRC placing Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix in September 2015. See Note 8 to the financial statements for further discussion of the NRC’s decision and Pilgrim’s response.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $60 million in 2016 compared to the reimbursement of approximately $2 million in 2015 of spent nuclear fuel storage costs previously recorded as other operation and maintenance expenses. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
a decrease of $32 million as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale; and
a decrease of $21 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The asset write-offs, impairments, and related charges variance is due to $2,836 million ($1,829 million net-of-tax) in 2016 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values, partially offset by $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of these charges.
Depreciation and amortization expenses decreased primarily due to:
decreases in depreciable asset balances as a result of the impairments of the FitzPatrick, Pilgrim, and Palisades plants. See Note 14 to the financial statements for further discussion of the impairments;
the effects of recording the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. The damages awarded include the reimbursement of approximately $15 million in 2016 compared to the reimbursement of approximately $4 million in 2015 of spent nuclear fuel storage costs previously recorded as depreciation. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation; and
a decrease in depreciable asset balances as a result of the sale of the Rhode Island State Energy Center in December 2015. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
The gain on sale of asset resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
Other expenses decreased primarily due to the reduction in deferred refueling outage amortization costs related to the impairments of the FitzPatrick, Pilgrim, and Palisades plants and related assets, partially offset by increases in decommissioning expenses primarily as a result of a trust transfer agreement Entergy entered into with NYPA in August 2016 to transfer the decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy and a revision to the estimated decommissioning cost liability for the Entergy Wholesale Commodities’ Pilgrim plant as a result of a revised decommissioning cost study in 2015. See Note 14 to the financial statements for further discussion of the impairments and related charges and Note 9 to the financial statements for further discussion of nuclear decommissioning costs.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Income Taxes
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.
The effective income tax rate for 2016 was 59.1%. The difference in the effective income tax rate versus the statutory rate of 35% for 2016 was primarily due to a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes and the reversal of a portion of the provision for uncertain tax positions as a result of the settlement of the 2010-2011 IRS audit, partially offset by state income taxes and certain book and tax differences related to utility plant items. See Note 3 to the financial statements for additional discussion of the tax election, the tax settlement, and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.
The effective income tax rate for 2015 was 80.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.
2015 Compared to 2014
Following are income statement variances for Utility, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2015 to 2014 showing how much the line item increased or (decreased) in comparison to the prior period.
|
| | | | | | | | | | | | | | | |
| | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy |
| | (In Thousands) |
| 2014 Consolidated Net Income (Loss) |
| $846,496 |
| |
| $294,521 |
| |
| ($180,760 | ) | |
| $960,257 |
|
| | | | | | | | |
| Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 94,195 |
| | (558,060 | ) | | (1,885 | ) | | (465,750 | ) |
| Other operation and maintenance | 166,812 |
| | (123,645 | ) | | 1,278 |
| | 44,445 |
|
| Asset write-offs, impairments, and related charges | (3,553 | ) | | 1,928,707 |
| | — |
| | 1,925,154 |
|
| Taxes other than income taxes | 35,010 |
| | (20,196 | ) | | 2 |
| | 14,816 |
|
| Depreciation and amortization | 57,076 |
| | (36,892 | ) | | (1,546 | ) | | 18,638 |
|
| Gain on sale of asset | — |
| �� | 154,037 |
| | — |
| | 154,037 |
|
| Other income | (3,993 | ) | | (4,899 | ) | | (18,607 | ) | | (27,499 | ) |
| Interest expense | 11,403 |
| | 10,142 |
| | (5,583 | ) | | 15,962 |
|
| Other expenses | 10,821 |
| | (19,533 | ) | | — |
| | (8,712 | ) |
| Income taxes | (455,387 | ) | | (787,327 | ) | | 10,190 |
| | (1,232,524 | ) |
| 2015 Consolidated Net Income (Loss) |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($205,593 | ) | |
| ($156,734 | ) |
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.
Results of operations for 2015 include $2,036 million ($1,317 million net-of-tax) of impairment and related charges to write down the carrying values of certain Entergy Wholesale Commodities’ plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of the stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and regulatory charges to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.
Results of operations for 2014 include $154 million ($100 million net-of-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of the assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 114 to the financial statements for further discussion of the charges. Results of operations for 2014 also include the $56.2 million ($36.7 million net-of-tax) write-off in 2014 of Entergy Mississippi’s
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.
Net Revenue
Utility
Following is an analysis of the change in net revenue comparing 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
| 2014 net revenue |
| $5,735 |
|
| Retail electric price | 187 |
|
| Volume/weather | 95 |
|
Louisiana business combination customer creditsWaterford 3 replacement steam generator provision | (10732 | ) |
| MISO deferral | (35 | ) |
Waterford 3 replacement steam generator provisionLouisiana business combination customer credits | (32107 | ) |
| Other | (14 | ) |
| 2015 net revenue |
| $5,829 |
|
The retail electric price variance is primarily due to:
formula rate plan increases at Entergy Louisiana, as approved by the LPSC, effective December 2014 and January 2015;
an increase in energy efficiency rider revenue primarily due to increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC, effective July 2015 and July 2014, and new energy efficiency riders at Entergy Louisiana and Entergy Mississippi that began in the fourth quarter 2014. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have a minimal effect on net income;2014; and
an annual net rate increase at Entergy Mississippi of $16 million, effective February 2015, as a result of the MPSC order in the June 2014 rate case.
See Note 2 to the financial statements for a discussion of rate and regulatory proceedings.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The volume/weather variance is primarily due to an increase of 1,402 GWh, or 1%, in billed electricity usage, including an increase in industrial usage and the effect of more favorable weather. The increase in industrial sales was primarily due to expansion in the chemicals industry and the addition of new customers, partially offset by decreased demand primarily due to extended maintenance outages for existing chemicals customers.
The Louisiana business combination customer credits varianceWaterford 3 replacement steam generator provision is due to a regulatory liabilitycharge of $107approximately $32 million recorded by Entergy in October 2015 as a result ofrelated to the Entergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of an agreement with the LPSC, electric customers of Entergy Louisiana will realize customer creditsuncertainty associated with the business combination; accordingly, in October 2015, Entergy recorded a regulatory liabilityresolution of $107 million ($66 million net-of-tax).the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for furthera discussion of the business combination and customer credits.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis replacement steam generator prudence review proceeding.
The MISO deferral variance is primarily due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC and the MPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.
The Waterford 3 replacement steam generator provisionLouisiana business combination customer credits variance is due to a regulatory chargeliability of approximately $32$107 million recorded by Entergy in October 2015 related toas a result of the uncertaintyEntergy Gulf States Louisiana and Entergy Louisiana business combination. Consistent with the terms of the stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the resolutionbusiness combination; accordingly, in October 2015, Entergy recorded a regulatory liability of the Waterford 3 replacement steam generator project.$107 million ($66 million net-of-tax). See Note 2 to the financial statements for afurther discussion of the Waterford 3 replacement steam generator prudence review proceeding.business combination and customer credits.
Entergy Wholesale Commodities
Following is an analysis of the change in net revenue comparing 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
| 2014 net revenue |
| $2,224 |
|
| Nuclear realized price changes | (310 | ) |
| Vermont Yankee shutdown in December 2014 | (305 | ) |
| Nuclear volume, excluding Vermont Yankee effect | 20 |
|
| Other | 37 |
|
| 2015 net revenue |
| $1,666 |
|
As shown in the table above, net revenue for Entergy Wholesale Commodities decreased by approximately $558 million in 20152016 primarily due to:
lower realized wholesale energy prices, primarily due to significantly higher Northeast market power prices in 2014, and lower capacity prices in 2015; and
a decrease in net revenue as a result of Vermont Yankee ceasing power production in December 2014.
The decrease was partially offset by higher volume in the Entergy Wholesale Commodities nuclear fleet, excluding Vermont Yankee, resulting from fewer refueling outage days in 2015 as compared to 2014, partially offset by more unplanned outage days in 2015 as compared to 2014.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Following are key performance measures for Entergy Wholesale Commodities for 2015 and 2014.
|
| | | |
| | 2015 | | 2014 |
| Owned capacity (MW) (a) | 4,880 | | 6,068 |
| GWh billed | 39,745 | | 44,424 |
| Average revenue per MWh | $51.88 | | $60.84 |
| | | | |
| Entergy Wholesale Commodities Nuclear Fleet | | | |
| Capacity factor | 91% | | 91% |
| GWh billed | 35,859 | | 40,253 |
| Average revenue per MWh | $51.49 | | $60.35 |
| Refueling Outage Days: | | | |
| FitzPatrick | — | | 44 |
| Indian Point 2 | — | | 24 |
| Indian Point 3 | 23 | | — |
| Palisades | 32 | | 56 |
| Pilgrim | 34 | | — |
| |
| (a) | The reduction in owned capacity is due to the retirement of the 605 MW Vermont Yankee plant in December 2014 and the sale of the 583 MW Rhode Island State Energy Center in December 2015. |
Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear Plants
The effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. The Entergy Wholesale Commodities nuclear business experienced an annual realized price per MWh of $51.49 in 2015, $60.35 in 2014, and $50.15 in 2013. The decrease in realized price in 2015 is primarily attributable to a significant increase in first quarter 2014 prices due to cold winter weather and northeastern U.S. gas pipeline infrastructure limitations. Prior to 2010 the annual realized price per MWh for Entergy Wholesale Commodities generally increased each year, reaching a peak of $61.07 in 2009. As shown in the contracted sale of energy table in “Market and Credit Risk Sensitive Instruments,” Entergy Wholesale Commodities has sold forward 86% of its planned nuclear energy output for 2016 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2015. In addition, Entergy Wholesale Commodities has sold forward 63% of its planned nuclear energy output for 2017 for an expected average contracted energy price of $46 per MWh based on market prices at December 31, 2015.
The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The severity of the challenge varies for each of the plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region.
In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The decisions to shut down the plants were primarily due to the poor market conditions that have led to reduced revenues, the poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick is expected to shut down at the end of its current fuel cycle, which is planned for January 27, 2017.
Entergy previously shut down Vermont Yankee in 2014, and, after the closures of Pilgrim and FitzPatrick, will have two remaining nuclear power generating facilities in operation in the Entergy Wholesale Commodities business,
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Indian Point and Palisades. Unlike the three facilities that Entergy has decided to shut down, Indian Point is a multi-unit site with both Indian Point 2 and 3 in operation that sells power at NYISO Zone G, which is a key supply region for New York City. In addition, Indian Point 2 (1,028 MW) and 3 (1,041 MW) are significantly larger plants than Vermont Yankee (605 MW), Pilgrim (688 MW), or FitzPatrick (838 MW). The Indian Point plants, however, are currently involved, and face opposition, in extensive licensing proceedings, which are described in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants.” Palisades (811 MW) is similar in size to FitzPatrick, is also a single-unit site, and the MISO market in which it operates has also experienced market price declines over the past few years. Most of the Palisades output, however, is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.
In 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 1 to the financial statements for further discussion of the impairments of the value of FitzPatrick, Pilgrim, and Palisades. Impairment of long-lived assets and nuclear decommissioning costs, and the factors that influence these items, are both discussed in “Critical Accounting Estimates” below. If economic conditions or regulatory activity no longer support the continued operation of Indian Point or Palisades for their expected lives or no longer support the recovery of the costs of the plants it could adversely affect Entergy’s results of operations through loss of revenue, impairment charges, increased depreciation rates, transitional costs, or accelerated decommissioning costs.
Other Income Statement Items
Utility
Other operation and maintenance expenses increased from $2,276 million for 2014 to $2,443 million for 2015 primarily due to:
an increase of $59 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs, higher labor costs, and an overall higher scope of work done in 2015. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s reactor oversight process action matrix. See “ANO Damage, Outage, and NRC Reviews” below for a discussion of the ANO stator incident and subsequent NRC reviews;
an increase of $28 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
an increase of $27 million in energy efficiency costs, including the effects of true-ups to energy efficiency filings for fixed costs to be collected from customers. These costs are recovered through energy efficiency riders in certain jurisdictions and have a minimal effect on net income;customers;
an increase of $26 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014; and
an increase of $24 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. The net income effect is partially offset by the method of recovery of these costs in certain jurisdictions. See Note 2 to the financial statements for further information on the recovery of these costs.
The increase was partially offset by a decrease of $23 million in storm damage accrualsprovisions primarily at Entergy Mississippi. See Note 2 to the financial statements for a discussion of storm cost recovery.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The asset write-offs, impairments, and related charges variance is due to the following activity:
the $45 million ($28 million net-of-tax) write-off in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project iswas no longer probable of recovery and the $16 million ($11 million net-of-tax) write-off in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam generator project prudence review;
the $23.5 million ($15.3 million net-of-tax) write-off in 2015 of the regulatory asset associated with the Spindletop gas storage facility as a result of the approval of the System Agreement termination settlement agreement; and
the $56 million ($37 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs.
See Note 2 to the financial statements for further discussion of the asset write-offs, impairments, and related charges.write-offs.
Taxes other than income taxes increased primarily due to increases in ad valorem taxes, payroll taxes, and franchise taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Ninemile Unit 6 project, which was placed in service in December 2014, and higher depreciation rates at Entergy Mississippi effective February 2015, as approved by the MPSC.
Interest expense increased primarily due to net debt issuances in the fourth quarter 2014 by certain Utility operating companies including the issuance by Entergy Louisiana in November 2014 of $250 million of 4.95% Series first mortgage bonds due January 2045 and the issuance by Entergy Arkansas in December 2014 of $250 million of 4.95% Series first mortgage bonds due December 2044.
Other expenses increased primarily due to increases in decommissioning expenses in 2015 as a result of revised decommissioning cost studies in 2014 for Grand Gulf, ANO1, ANO2,ANO 1, ANO 2, and Waterford 3. See Note 9 to the financial statements for further discussion of the revised decommissioning cost studies.
Entergy Wholesale Commodities
Other operation and maintenance expenses decreased from $1,023 million for 2014 to $899 million for 2015 primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014. The decrease was partially offset by an increase of $12 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefit costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The asset write-offs, impairments, and related charges variance is primarily due to $2,036 million ($1,317 million net-of-tax) in 2015 of impairment and related charges to write down the carrying values of the FitzPatrick, Pilgrim, and Palisadescertain Entergy Wholesale Commodities’ plants and related assets to their fair values, partially offset by $107 million ($69 million net-of-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014. See Note 114 to the financial statements for further discussion of these charges.
Taxes other than income taxes decreased primarily due to the shutdown of Vermont Yankee, which ceased power production in December 2014.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Depreciation and amortization expenses decreased primarily due to decreases in depreciable asset balances as a result of the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 114 to the financial statements for further discussion of impairment of long-lived assets.
The gain on sale of businessasset resulted from the sale in December 2015 of the 583 MW Rhode Island State Energy Center in Johnston, Rhode Island, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale. See Note 14 to the financial statements for further discussion of the Rhode Island State Energy Center sale.
Other income decreased primarily due to $37 million ($24 million net-of-tax) in 2015 of impairment and related charges resulting from the write-down of the carrying values of the generating assets of Entergy’s equity method investee Top Deer Wind Ventures, LLC to their fair values, partially offset by higher realized gains on decommissioning trust fund investments in 2015 as compared to 2014, including portfolio reallocations for the Vermont Yankee nuclear decommissioning trust funds.
Other expenses decreased primarily due to a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage as a result of the impairments and related charges in 2015 to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets and the shutdown of Vermont Yankee, which ceased power production in December 2014. See Note 114 to the financial statements for further discussion of the impairment and related charges.
Income Taxes
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.
The effective income tax rate for 2015 was 80.4%. The difference in the effective income tax rate versus the statutory rate of 35% for 2015 was primarily due to the tax effects of the Louisiana business combination coupled with the loss before income taxes resulting from the nuclear plant impairments previously discussed.combination. See Note 3 to the financial statements for further discussion of the tax effects of the Louisiana business combination and a reconciliation of the federal statutory rate of 35% to the effective income tax rate.
The effective income tax rate for 2014 was 38%. The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.
Entergy CorporationANO Damage, Outage, and Subsidiaries
Management’s Financial Discussion and Analysis
2014 Compared to 2013NRC Reviews
Following are income statement variancesIn March 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. Entergy Arkansas is pursuing its options for Utility,recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Wholesale Commodities, Parent & Other, and Entergy comparing 2014 to 2013 showing how much the line item increased or (decreased) in comparisonArkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the prior period.
|
| | | | | | | | | | | | | | | |
| | Utility | | Entergy Wholesale Commodities | | Parent & Other | | Entergy |
| | (In Thousands) |
| 2013 Consolidated Net Income (Loss) |
| $846,215 |
| |
| $42,976 |
| |
| ($158,619 | ) | |
| $730,572 |
|
| | | | | | | | |
Net revenue (operating revenue less fuel expense, purchased power, and other regulatory charges/credits) | 210,893 |
| | 422,147 |
| | (17,519 | ) | | 615,521 |
|
| Other operation and maintenance | 12,369 |
| | (25,043 | ) | | (8,724 | ) | | (21,398 | ) |
| Asset write-offs, impairments, and related charges | 62,814 |
| | (221,809 | ) | | (2,790 | ) | | (161,785 | ) |
| Taxes other than income taxes | 2,760 |
| | 1,709 |
| | (213 | ) | | 4,256 |
|
| Depreciation and amortization | (2,019 | ) | | 60,053 |
| | (440 | ) | | 57,594 |
|
| Gain on sale of business | — |
| | (43,569 | ) | | — |
| | (43,569 | ) |
| Other income | 1,795 |
| | (23,642 | ) | | (13,272 | ) | | (35,119 | ) |
| Interest expense | 22,556 |
| | 323 |
| | 591 |
| | 23,470 |
|
| Other expenses | 7,696 |
| | 33,699 |
| | — |
| | 41,395 |
|
| Income taxes | 106,231 |
| | 254,459 |
| | 2,926 |
| | 363,616 |
|
| 2014 Consolidated Net Income (Loss) |
| $846,496 |
|
|
| $294,521 |
|
|
| ($180,760 | ) |
|
| $960,257 |
|
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES” which accompaniesIn addition, Entergy Corporation’s financial statements in this reportArkansas incurred replacement power costs for further information with respect to operating statistics.ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned
Results of operations for 2014 include $154 million ($100 million net-of-tax) of charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completed in the third quarter 2014 along with reassessment of the assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 1 to the financial statements for further discussion of the charges. Results of operations for 2014 also include the $56.2 million ($36.7 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.
As discussed in more detail in Note 1 to the financial statements, results of operations for 2013 include $322 million ($202 million net-of-tax) of impairment and other related charges to write down the carrying value of Vermont Yankee and related assets to their fair values. Also, earnings were negatively affected in 2013 by expenses, including other operation and maintenance expenses and taxes other than income taxes, of approximately $110 million ($70 million net-of-tax), including approximately $85 million ($55 million net-of-tax) for Utility and $25 million ($15 million net-of-tax) for Entergy Wholesale Commodities, recorded in connection with a strategic imperative intended to optimize the organization through a process known as human capital management. In December 2013, Entergy deferred for future collection approximately $45 million ($30 million net-of-tax) of these costs in the Arkansas and Louisiana jurisdictions at the Utility, as approved by the APSC and the LPSC, respectively. See “Human Capital Management Strategic Imperative” below for further discussion.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Net Revenue
Utility
Following is an analysisduration of the change in net revenue comparingrefueling outage. In February 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $5,524 |
|
Retail electric price | 135 |
|
Asset retirement obligation | 56 |
|
Volume/weather | 36 |
|
MISO deferral | 16 |
|
Net wholesale revenue | (29 | ) |
Other | (3 | ) |
2014 net revenue |
| $5,735 |
|
The retail electric price variance is primarily due to:
increases in the energy efficiency rider at Entergy Arkansas, as approved by the APSC effective July 2013 and July 2014. Energy efficiency revenues are offset by costs included in other operation and maintenance expenses and have minimal effect on net income;
the effect of the APSC’s order inapproved Entergy Arkansas’s 2013request to exclude from the calculation of its revised energy cost rate case, including an annual base rate increase effective January 2014 offset by a MISO rider to provide customers credits$65.9 million of deferred fuel and purchased energy costs incurred in rates for transmission revenue received through MISO;
a formula rate plan increase at Entergy Mississippi, as approved by the MSPC, effective September 2013;
an increase in Entergy Mississippi’s storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income;
an annual base rate increase at Entergy Texas, effective April 2014,2013 as a result of the PUCT’s orderANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the September 2013 rate case; and
a formula rate plan increase at Entergy Louisiana, as approved by the LPSC, effective December 2014.ANO stator incident is available.
See NoteShortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.
In March 2015, after several NRC inspections and regulatory conferences, the financial statementsNRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with flood barrier effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for a discussionthe NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also incurred approximately $44 million in 2016 in support of rate proceedings.NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A lesser amount of incremental expense is expected to be ongoing annually after 2016, until ANO transitions out of Column 4.
The NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the completion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4.
Entergy Wholesale Commodities Exit from the Merchant Power Business
Entergy management has undertaken a strategy to manage and reduce the risk of the Entergy Wholesale Commodities business, which includes taking actions to reduce the size of the merchant fleet. Management evaluated the challenges for each of the plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement obligation affects net revenue because Entergy records a regulatory debit or creditcosts. Management continues to look for ways to mitigate the difference between asset retirement obligation-related expensesoperational and trust earnings plus asset retirement obligation-related costs collecteddecommissioning risks associated with the merchant power business. Assumptions regarding the operating life of the plants and the decommissioning timeline and process continue to be evaluated. Changes to current assumptions could result in revenue. The variance is primarily caused by increases in regulatory credits because of decreases in decommissioning trust earnings and increases in depreciation and accretion expenses and increases in regulatory creditsrevisions to realign the asset retirement obligation regulatory assetsobligations and affect compliance with regulatory treatment.
The volume/weather variance is primarily duecertain NRC minimum financial assurance requirements for meeting obligations to an increase of 3,129 GWh, or 3%,decommission the plants. Increases in billed electricity usage primarily due tothe asset retirement obligations could result in an increase in sales to industrial customers andoperating expense in the effect of more favorable weather on residential sales. The increase in industrial sales was primarily due to expansions, recoveryperiod of a major refining customer fromrevision. Assumptions regarding the possibility that a plant may have an unplanned outage in 2013, and continued moderate growthoperating life shorter than previously assumed will likely result in the manufacturing sector.need for additional contributions to decommissioning trust funds, or the posting of parent guarantees, letters of credit, or other surety mechanisms.
The MISO deferral variance is primarily due to the deferral in 2014 of the non-fuel MISO-related charges, as approved by the LPSC and the MPSC, partially offset by the deferral in April 2013, as approved by the APSC, of costs incurred from March 2010 through December 2012 related to the transition and implementation of joining the MISO
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
RTO. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.
The net wholesale variance is primarily due to a wholesale customer contract termination in December 2013 and lower margins on co-owner contracts due to contract changes.
Entergy Wholesale Commodities
Following is an analysis includes the ownership of the change in net revenue comparing 2014 to 2013.following nuclear reactors:
|
| | | |
| Amount |
| (In Millions) | | |
| | |
2013 net revenueLocation |
| $1,802Market |
| Capacity | | Planned Transaction |
Nuclear realized price changesVermont Yankee | 393 |
Vernon, VT | | ISO-NE | | 605 MW | | Planned sale of shutdown plant in 2018 |
Nuclear volumeFitzPatrick | 37 |
Oswego, NY | | NYISO | | 838 MW | | Planned sale in 2017 |
OtherPalisades | (8 | )Covert, MI | | MISO | | 811 MW | | Planned shutdown in 2018 |
2014 net revenuePilgrim |
| $2,224Plymouth, MA |
| ISO-NE | | 688 MW | | Planned shutdown in 2019 |
| Indian Point 2 | | Buchanan, NY | | NYISO | | 1,028 MW | | Planned shutdown in 2020 |
| Indian Point 3 | | Buchanan, NY | | NYISO | | 1,041 MW | | Planned shutdown in 2021 |
As shown in the table above, net revenue for Entergy Wholesale Commodities increased by approximately $422 millionalso includes the ownership of two non-operating nuclear facilities, Big Rock Point in 2014 primarily due to:
higher realized wholesale energy prices primarily due to increasesMichigan and Indian Point 1 in Northeast market power pricesNew York that were acquired when Entergy purchased the Palisades and higher capacity prices. Entergy Wholesale Commodities’ hedging strategies routinely include financial instruments that manage operational and liquidity risk.Indian Point 2 nuclear plants, respectively. These positions,facilities are in addition to a larger-than-normal unhedged position in 2014 due to Vermont Yankee being in its final yearvarious stages of operation, allowedthe decommissioning process. In addition, Entergy Wholesale Commodities provides operations and management services, including decommissioning services, to benefit from increasesnuclear power plants owned by other utilities in Northeast market power prices; and
higher volume in its nuclear fleet resulting from approximately 90 fewer unplanned outage days in 2014 compared to 2013, partially offset by a larger exercisethe United States. A relatively minor portion of resupply options in 2013 compared to 2014 provided for in purchase power agreements wherethe Entergy Wholesale Commodities may electbusiness is the ownership of interests in non-nuclear power plants that sell the electric power produced by those plants 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.wholesale customers.
Following are key performance measures forShutdown and Planned Sale of Vermont Yankee
On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase.In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for 2014the spent fuel management and 2013.decommissioning of the plant.
Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $100 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility, and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to the Entergy entity selling the membership interests in Entergy Nuclear Vermont Yankee. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $45 million as of December 31, 2016, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2016, was approximately $88 million.
Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018, subject to obtaining necessary regulatory approvals, in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site restoration, subject to extension not to exceed two years from partial site restoration.
The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of site restoration standards that will be proposed as part of the
|
| | | |
| | 2014 | | 2013 |
| Owned capacity (MW) | 6,068 | | 6,068 |
| GWh billed | 44,424 | | 45,127 |
| Average revenue per MWh | $60.84 | | $50.86 |
| |
| | |
| Entergy Wholesale Commodities Nuclear Fleet |
| | |
| Capacity factor | 91% | | 89% |
| GWh billed | 40,253 | | 40,167 |
| Average revenue per MWh | $60.35 | | $50.15 |
| Refueling Outage Days: | | | |
| FitzPatrick | 44 | | — |
| Indian Point 2 | 24 | | — |
| Indian Point 3 | — | | 28 |
| Palisades | 56 | | — |
| Pilgrim | — | | 45 |
| Vermont Yankee | — | | 27 |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Itemstransaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. The transaction is expected to close by the end of 2018, subject to certain conditions, including the condition that Entergy contribute to the decommissioning trust fund if the value is less than provided for in the agreement with NorthStar.
UtilitySale of Rhode Island State Energy Center
Other operationIn December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and maintenance expenses increased from $2,264realized a pre-tax gain of $154 million for 2013 to $2,276 million for 2014 primarily due to:on the sale.
an increaseSale of $53 millionTop Deer Investment
In November 2016, Entergy sold its 50% membership interest in nuclearTop Deer Wind Ventures, LLC, a wind-powered electric generation expenses primarily due to higher material costs, higher contract labor costs, and higher NRC fees;
an increase of $38 million in administration fees related to participationjoint venture owned by Entergy in the MISO RTO beginning December 2013.Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.
Planned Sale of FitzPatrick
In October 2015, Entergy determined that it would close the FitzPatrick plant. The net income effect is partially offset dueoriginal expectation was to deferralsshut down the FitzPatrick plant at the end of these feesits fuel cycle in certain jurisdictions.January 2017. See Note 214 to the financial statements for further informationdiscussion of the impairment charges associated with the decision to cease operations earlier than expected.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. When Entergy purchased Indian Point 3 and FitzPatrick in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. NYPA had the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. Under the original agreements, if the decommissioning liabilities were retained by NYPA, the Entergy subsidiaries would perform the decommissioning of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trust funds. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset was increased by monthly accretion based on the deferrals;
an increaseapplicable discount rate necessary to ultimately provide for the estimated future value of $29 million in energy efficiency costs. These costs are recovered through energy efficiency riders and havethe decommissioning contract. The monthly accretion was recorded as interest income. As a minimal effect on net income;
an increaseresult of $24 million in storm damage accruals primarily at Entergy Arkansas effective January 2014, as approved by the APSC, and at Entergy Mississippi effective October 2013, as approved by the MPSC;
an increase of $20 million in regulatory, consulting, and legal fees;
an increase of $19 million in contract labor primarily due to higher infrastructure and application services and call center outsourcing;
an increase of $11 million primarily due to higher vegetation maintenance;
an increase of $7 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013;
an increase of $7 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and
several individually insignificant items.
The increase was partially offset by:
a decrease of $146 million in compensation and benefits costs primarily due to fewer employees, an increaseagreement with NYPA, in the discount rates usedthird quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The asset retirement obligations are accreted monthly through a charge to determine net periodic pensiondecommissioning expense. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and other postretirement benefit costs, other postretirement benefit plan design changes, and a settlement charge recognizedFitzPatrick plants were transferred to Entergy by NYPA in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan.January 2017. See “Critical Accounting Estimates” below and Note 119 to the financial statements for further discussion of benefits costs;
a decrease of $36 million resulting from costs incurred in 2013 related to the now-terminated plan to spin offIndian Point 3 and merge the Utility’s transmission business;
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage,FitzPatrick’s decommissioning liabilities and NRC Reviews” below for further discussion of the incident;
a net decrease of $8 million related to the human capital management strategic imperative in 2014 as compared to 2013 including a decrease of $60 million in implementation costs, severance costs, and curtailment and special termination benefits, the deferral in 2013 of $44 million of costs incurred, as approved by the APSC and LPSC, and partial amortization in 2014 of $8 million of costs that were deferred in 2013. See “Human Capital Management Strategic Imperative” below for further discussion; and
a net decrease of $4 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” insee Note 816 to the financial statements for further discussion.
discussion of the receivables for the beneficial interests in Indian Point 3 and FitzPatrick’s decommissioning trust funds.
In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The asset write-offs, impairment,transaction is expected to close in the first half of 2017. The purchase price is $100 million and the assumption by Exelon of certain liabilities related charges variance is due to the $56.2FitzPatrick plant, with an additional $10 million ($36.7 million net-of-tax) write-off in 2014 of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs and a $16 million ($10.5 million net-of-tax) write-off recorded in 2014 because of the uncertainty associatednon-refundable signing fee, which was paid
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
upon the signing of the agreement. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the resolutionEnergy Research and Development Authority of the Waterford 3 replacement steam generator project prudence review. See Note 2State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017. Entergy expects to operate the FitzPatrick plant until the asset purchase agreement closing date. Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon will reimburse Entergy for specified out-of-pocket costs associated with the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Pursuant to the financial statementsreimbursement agreement, as of December 31, 2016 Exelon reimbursed Entergy $56 million for further discussion of new nuclear generation development costsfuel expenses and the prudence review.
Interest expense increased primarily due to the lease renewal in December 2013 of the Grand Gulf sale leaseback and net debt issuances of first mortgage bonds in the first quarter 2014 and the second quarter 2013 by certain Utility operating companies. See Note 5 to the financial statements$41 million for more details of long-term debt. The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project.
Other expenses increased primarily due to increases in decommissioning expenses resulting from revisions to the estimated decommissioning cost liabilities as a result of revised decommissioning cost studies in the fourth quarter 2013 and the first quarter 2014, partially offset by a decrease in nuclear refueling outage costs that are being amortized over the estimated period to the next outage. See Note 9 to the financial statements for further discussion of the decommissioning cost revisions.
Entergy Wholesale Commodities
Otherother operation and maintenance expenses decreasedassociated with preparing to refuel FitzPatrick in 2017. In addition, Entergy entered into a transfer agreement whereby Exelon will be entitled to all revenues from $1,048FitzPatrick’s electricity and capacity sales for the period that commenced upon completion of the refueling outage through the asset purchase agreement closing date. If the asset purchase agreement is terminated, a termination fee of up to $30 million will be payable to Entergy under certain circumstances. If it is consummated, the transaction could result in a gain or loss because of fluctuations in the decommissioning trust fund earnings and asset retirement obligation accretion. Upon the closing of the sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon.
As a result of the agreement and the status of the necessary regulatory approvals, the assets and liabilities associated with the sale of FitzPatrick to Exelon are classified as held for sale on Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet. As of December 31, 2016, the $785 million receivable for the beneficial interest in the decommissioning trust fund within other deferred debits and the $714 million asset retirement obligation within other non-current liabilities are classified as held for sale. The transaction also includes property, plant, and equipment with a net book value of zero.
Planned Shutdown of Palisades
Most of the Palisades output is sold under a power purchase agreement (PPA) with Consumers Energy, entered into when the plant was acquired in 2007, that is currently scheduled to expire in 2022. The PPA prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022.
In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Pursuant to the PPA termination agreement, Consumers Energy will pay Entergy $172 million for 2013the early termination of the PPA. The PPA termination agreement is subject to $1,023 millionregulatory approvals. Separately, and assuming regulatory approvals are obtained for 2014 primarily due to:
a decrease of $63 million in compensation and benefits costs primarily duethe PPA termination agreement, Entergy intends to fewer employees, an increaseshut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the discount rates usedspring of 2017 and operating through the end of that fuel cycle. Entergy expects to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, andenter into a settlement charge recognized in September 2013 relatednew PPA with Consumers Energy under which the plant would continue to the payment of lump sum benefits out of the non-qualified pension plan.operate through October 1, 2018. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of benefits costs;
a decrease of $15 million due to the absence of expenses from Entergy Solutions District Energy, which was sold in November 2013; and
a decrease of $13 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to 2013. See “Human Capital Management Strategic Imperative” below for further discussion.
The decrease was partially offset by:
an increase of $22 million incurred in 2014 as compared to 2013 related to the shutdown of Vermont Yankee including severance and retention costs. See “Impairment of Long-Lived Assets” in Note 114 to the financial statements for discussion regarding the shutdown of the Vermont Yankee plant in December 2014;
an increase of $18 million primarily dueimpairment charges associated with the PPA termination agreement and the decision to higher contract costs and higher NRC fees; and
$18 million in transmission imbalance sales in 2013.cease operations earlier than expected.
Planned Shutdown of Pilgrim
In October 2015, Entergy determined that it would close the Pilgrim plant. The asset write-offs, impairments,decision came after management’s extensive analysis of the economics and related charges varianceoperating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. The Pilgrim plant is primarily dueexpected to $321.5 million ($202.2 million net-of-tax) in 2013 of impairment and other related charges primarily to write down the carrying value of Vermont Yankee and related assets to their fair values and $107.5 million ($69.8 million net-of-tax) in 2014 of impairment charges related to Vermont Yankee primarily resulting from the effects of an updated decommissioning cost study completedcease operations on May 31, 2019, after refueling in the third quarter 2014.spring of 2017 and operating through the end of that fuel cycle. See Note 114 to the financial statements for further discussion of these impairment charges.
Depreciation and amortization expenses increased primarily due to a change effective in 2014 in the estimated average useful lives of plant in service as a result of a new depreciation study and an increase to depreciable plant balances.
The gain on sale of business resulted from the sale in November 2013 of Entergy Solutions District Energy, a business wholly-owned by Entergy in the Entergy Wholesale Commodities segment that owned and operated district
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
energy assets servicingdiscussion of the business districts in Houstonimpairment charges associated with the decision to cease operations earlier than expected and New Orleans. Entergy sold Entergy Solutions District Energysee Note 8 for $140 million and realized a pre-tax gain of $44 millionfurther discussion on the sale.placement of Pilgrim in Column 4.
Other income decreased primarily duePlanned Shutdown of Indian Point 2 and Indian Point 3
Indian Point 2 and Indian Point 3 have been involved, and have faced opposition, in extensive licensing proceedings. In January 2017, Entergy announced that it reached a settlement with New York State to lower realized gains on nuclearshut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. See further discussion of the licensing proceedings and the settlement reached with New York State in “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants”below.
As discussed above, in August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust fund investments.
Other expenses increased primarily due to an increase in nuclear refueling outage costs that are being amortized over the estimated period to the next outage and an increase in decommissioning expenses primarily due to revisions to the estimated decommissioning cost liability for Vermont Yankee recordedthe Indian Point 3 plant to Entergy. The decommissioning trust fund for the Indian Point 3 plant was transferred to Entergy by NYPA in the third and fourth quarters of 2013. See “Critical Accounting Estimates - Nuclear Decommissioning Costs” below for further discussion of nuclear decommissioning costs.
Income TaxesJanuary 2017.
See Note 314 to the financial statements for a reconciliationfurther discussion of the federal statutory rateimpairment charges associated with management’s evaluation of 35%alternatives to the effective income tax rates, and for additional discussion regarding income taxes.continued operation of the Indian Point plants.
The effective income tax rate for 2014 was 38%. The difference in the effective income tax rate versus the statutory rate of 35% for 2014 was primarily due to state income taxes, certain book and tax differences related to utility plant items, and the provision for uncertain tax positions, partially offset by a deferred state income tax reduction related to a New York tax law change and book and tax differences related to the allowance for equity funds used during construction.Costs Associated with Entergy Wholesale Commodities Strategic Transactions
The effective income tax rate for 2013 was 23.6%. The differenceEntergy incurred approximately $95 million in costs in 2016 associated with these strategic decisions and transactions to exit the effective income tax rate versusmerchant power business, primarily employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. Entergy expects to incur employee retention and severance expenses of approximately $100 million in 2017, and approximately $235 million from 2018 through the statutory rateend of 35% for 2013 was primarily related to IRS settlements as discussed further in2021 associated with these strategic transactions. See Note 313 to the financial statements and a tax benefit associated with the now-terminated plan to spin off and merge the Utility’s transmission business, because certain associated costs became deductible with the terminationfor further discussion of the transaction.these costs.
Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Power Plants
The NRC operating license for Palisades expires in 2031, for Pilgrim expires in 2032, and for FitzPatrick expires in 2034. ForSee Note 14 to the financial statements for additional discussion regarding the shutdownplanned sales of the Vermont Yankee plant in December 2014and FitzPatrick plants and the planned shutdown ofshutdowns and associated impairment and related charges for the FitzPatrickPalisades and Pilgrim plants, see “Impairment of Long-Lived Assets” in Note 1 to the financial statements.plants.
Indian Point NRC/ASLB Proceedings
In January 2017, Entergy reached a settlement with New York State, several State agencies, and Riverkeeper, Inc. under which Indian Point 2 and Indian Point 3 will cease commercial operation by April 30, 2020 and April 30, 2021, respectively, subject to certain conditions, including New York State’s withdrawal of opposition to Indian Point’s license renewals and issuance of contested permits and similar authorizations. See “Overview of Settlement” below for further discussion on the settlement with New York State.
In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were in September 2013 and December 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Each of Indian Point 2 and Indian Point 3 has now entered its “period of extended operation” after expiration of the plant’s initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The scope of NRC license renewal applications is focused primarily on whether the licensee has in place aging management programs (detailed diagnostic analyses performed when and as prescribed) to ensure that passive systems, structures, and components (such as pipes and concrete and metal structures) can continue to perform their intended safety functions. Other aspects of nuclear plant operations (maintenance of active components like pumps and control systems, security, and emergency preparedness) are regulated by the NRC on an ongoing basis and, as such, are outside
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
the scope of license renewal proceedings. The NRC also determines whether there are any environmental impacts that would affect license renewal.
Every application for renewal of a reactor operating license undergoes comprehensive NRC staff review to ensure the adequacy of the application and the aging management programs detailed in it. NRC staff’s conclusions following such review are set forth in a Final Safety Evaluation Report (FSER). Issuance of a renewed operating license is a “major federal action” under the National Environmental Policy Act, so NRC staff also are required to prepare an Environmental Impact Statement (EIS) regarding the proposed licensing action. The NRC has elected to address certain EIS issues on a generic basis via the rulemaking process. As a result, the EIS for a particular license renewal proceeding has two components: the Generic Environmental Impact Statement and a Final Supplemental Environmental Impact Statement (FSEIS) addressing site-specific EIS issues. Both the FSER and the FSEIS are subject to updating by NRC staff in an individual license renewal proceeding.
Where, as in the case of Indian Point, one or more intervenors proposes for admission contentions alleging errors and omissions in the applicant’s license renewal application or the NRC staff’s review of related safety and environmental issues, the NRC appoints an ASLB to determine whether the contentions satisfy threshold standards and, if so, to adjudicate such “admitted” contentions. Safety-related contentions address issues that will be or have been described in the FSER;FSER and environmental-related contentions address issues that will be or have been described in the FSEIS. Contentions may be proposed at any time before license issuance based on new and material information, subject to timeliness and admissibility standards. Final ASLB orders on admissibility or resolving contentions, whether after hearing or on summary disposition, are appealable to the NRC.
Various governmental and private intervenors have sought and obtained party status to express opposition to renewal of the Indian Point 2 and Indian Point 3 licenses. The ASLB has admitted 16 consolidated contentions based on 21 contentions originally proposed by the State of New York or other parties.
Four of the 16 admitted Thirteen “Track 1” contentions have been resolved by the ASLB without hearing, two by means of ASLB-approved settlements, a third by summary disposition as described below, and a fourth by motion to dismiss as moot as described below. 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 FSEIS as 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. Entergy renewed its appeal in February 2014 in conjunction with the filing of Track 1 appeals, as discussed further below. In May 2013, Entergy filed an updated SAMA cost analysis with the NRC, and in July 2013 the ASLB granted Entergy’s motion for clarification that a future NRC staff filing would be the trigger for potential new or amended contentions on the SAMA update.
Nine of the remaining admitted contentions were designated by the ASLB as “Track 1” and were subject to hearings over 12 days in October, November, and December 2012. In November 2013 the ASLB issued a decision on the nine Track 1 contentions. The ASLB resolved eight Track 1 contentions favorably to Entergy. No appeal was taken from the ASLB’s decision on six of those eight contentions, so they have been conclusively resolved in Entergy’s favor. The ASLB resolved one Track 1 contention favorably to New York State. That contention was based on a dispute over the characterization of certain electrical equipment as “active” or “passive.” The ASLB found in favor of the State of New York despite precedent supporting the characterization advocated by Entergy and NRC staff.
Following the ASLB’s November 2013 decision on Track 1 contentions, the State of New York and Clearwater each appealed the decision on a single contention (SAMA decontamination cost estimates for the State of New York and environmental justice for Clearwater), while Riverkeeper filed no appeals. Entergy and NRC staff both appealed
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
the same three issues: (1) the ASLB’s decision on electrical transformers; (2) certain intermediate determinations in the ASLB’s overall favorable decision on environmental justice; and (3) the ASLB’s earlier decisions on SAMA cost estimates, thus renewing their appeals of that issue previously denied by the NRC as premature. Appeal (3) addressed a contention that was one of the four decided without hearing. The remaining appeals addressed contentions that were tried in Track 1 hearings.
In February 2015, the NRC granted petitions for review of two appeals for the purpose of obtaining additional information prior to making final disposition. The appeals for which the NRC requested answers to specified questions were New York State’s appeal on SAMA decontamination cost estimates and the appeal of Entergy and NRC staff on SAMA cost estimates. The NRC stated that the remaining appeals filed after the ASLB’s Track 1 decision would be resolved in the future.
In March 2015 the NRC resolved the remaining appeals from the ASLB’s Track 1 decisions in favor of Entergy, and the NRC staff. Those appeals addressed electrical transformers and environmental justice. All filings in response to the NRC’s request for additional information on SAMA issues raised by the pending two SAMA-related appeals have been completed. There is no deadline for the NRC to act on the SAMA-related appeals.
The remaining four admitted consolidated contentions were designatedwhether by the ASLB as “Track 2.” In April 2014or by the ASLB granted Entergy’s motion to dismiss as moot a contention by Riverkeeper alleging that the FSEIS failed to adequately address endangered species issues. At the same time, the ASLB denied a motion filed by Riverkeeper in August 2013 to amend its endangered species contention. These ASLB decisions were not appealed and are now final, making a total of 11 of the original 16 admitted consolidated contentions that have been resolved favorably (or in the case of settlement, acceptably) to Entergy. Five of the original 16 admitted consolidated contentions areNRC on appeal (two total) or pendingfrom an ASLB decision on Track 2 (three total).
Track 2 hearingsdecision. Hearings on the three remaining Trackcontentions, which are designated “Track 2, contentions, all of which relate to safety,” were conducted by the ASLB in November 2015. The ASLB has scheduled the filing of post-hearing submissions through late-March 2016, but extended that schedule several times to allow the submission of proposed findingssupplemental testimony addressing the results of fact and conclusionsthe 2016 reactor vessel internal inspection at Unit 2. That inspection led to the replacement of law and a reply to other parties’ proposed findings and conclusions through late-March 2016. There is no deadline forsubstantial number of baffle former bolts, as described further in “Nuclear Matters” below. In January 2017 the ASLB to issue a decision onissued an order suspending the schedule for completion of Track 2 contentions. The disappointed party may appeal tofilings following notification of the NRC and, ultimately, to the federal courts.settlement with New York State.
Independent of the ASLB process, the NRC staff has performed its technical and environmental reviews of the Indian Point 2 and Indian Point 3 license renewal application. The NRC staff issued an FSER in August 2009, a supplement to the FSER in August 2011, an FSEIS in December 2010, a supplement to the FSEIS in June 2013, and as noted above, a further supplement to the FSER in November 2014. In November 2014 the NRC staff advised of its proposed schedule for issuance of a further FSEIS supplement to address new information received by NRC staff since preparation and publication of the previous FSEIS supplement in June 2013. The matters to be addressed in the new supplement include Entergy’s May 2013 submittal of updated cost information for SAMAs; Entergy’s February 2014 submittal of new aquatic impact information; the June 2013 revision by the NRC of its Generic Environmental Impact Statement relied upon in license renewal proceedings; and the NRC’s Continued Storage Of Spent Nuclear Fuel rule, which was published in the Federal Register in September 2014. The NRC staff issued a draft of the new FSEIS supplement in December 2015. Under the updated schedule, the newThe target date for issuance of a final FSEIS supplement is expectedhas not been announced. In addition, NRC staff has not formally announced whether it plans to be issuedissue a further FSEIS supplement addressing sensitivity analyses of severe accident mitigation alternatives that the NRC directed staff to perform as part of an order resolving appeal of one Track 1 contention in September 2016.favor of NRC staff and Entergy.
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 and appeals processes as authorized by the NRC regulations. As noted in Entergy filings at the ASLB and the appellate levels, 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 Indian Point 3 license renewal applications. See “Nuclear Matters” below for discussion of spent nuclear fuel storage issues and their potential effect on the timing of license renewals.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Indian Point NYSDEC Water Quality Certification Proceedings
The New York State Department of Environmental Conservation (NYSDEC) 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 NYSDEC in April 2009, with a reservation of rights regarding the applicability of Section 401 in this case. AfterSubsequently, Entergy submitted certain additional information in response to NYSDEC requests for additional information, ininformation. 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. TheBetween 2011 and 2016, the ALJs conducted more than 50 days of trial on issues identified by NYSDEC staff decision does not restrictas bases for denying Indian Point operations, butPoint’s proposed water quality certificate, and those issues were briefed by the issuance of a certification is potentially required priorparties. Entergy also submitted information and analysis to NRC issuance of renewed unit licenses. In June 2011, Entergy filed notice with the NRC indicating that NYSDEC, the agency that would issue or deny a water quality certificationcertificate was not legally required for license renewal; NYSDEC disputed Entergy’s position. At the time the Indian Point license renewal process, had taken longer than one year to take final action on Entergy’s application for a water quality certification and, therefore, had 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 disagreessettlement 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 ALJs 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. In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. The NYSDEC staff also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. In January 2015, Entergy wrote NYSDEC leadership requesting an explanation of the delay in release of the ruling following an ALJ’s on-record statement that the ALJ’s draft rulingNew York State was under “executive review.” In February 2015reached, the ALJs issued a ruling scheduling hearings on the outage proposals and other pending issues. In March 2015 the NYSDEC staff withdrew from consideration at trial before the ALJs its proposal for annual fish protection outages of 92 days. The NYSDEC staff and Riverkeeper continue to advance other annual outage proposals. The NYSDEC staff also withdrew from further consideration a $24 million annual interim payment that had been proposed as a condition of the draft water pollution control permit. Hearings on the outages proposal were held in September 2015, and post-hearing briefing on both the closed cycle cooling proposal and the outages proposal has been scheduled for May and July 2016.
The ALJs havenot issued no partial decisions on the several issues that have been the subject of hearing during the past four years and have not announced a schedule for doing so. After the completion of hearings on the merits, the ALJs will issue a recommended decision to the Commissioner.
Under the Indian Point settlement, in January 2017, the NYSDEC Commissioner’s designated delegate who will then issueCommissioner approved the final agency decision. A party toNYSDEC staff’s earlier issuance of the proceeding can appealwater quality certification and water discharge permit, and the final agency decision to state court.ALJs terminated the proceedings. The settlement agreement provides for issuance of a supplemental environmental analysis in May 2017 reflecting early shutdown.
Indian Point Coastal Zone Management Act Proceedings
In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). Most commonly, those requirements are met by the applicant’s demonstration that the activity authorized by the federal permit being sought is consistent with the host state’s federally-approved coastal management policies. Entergy has undertaken three independent initiatives to resolve CZMA issues: “grandfathering;” “previous review;” and a “consistency certification.”
First, Entergy filed with the New York State Department of State (NYSDOS) in November 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. NYSDOS denied the motion by order dated January 2013. Entergy filed a petition for judicial review ofappealed NYSDOS’s decision withto the New York State Supreme Court for Albany County in March 2013. The court denied Entergy’s appeal in December 2013. Entergy initiated an appeal to the Appellate Division ofcourts. In November 2016 the New York State Supreme Court in January 2014. In December 2014 a five-judge panel of that court unanimouslyAppeals held that Indian Point is exempt from
Entergy Corporationwas not grandfathered, and Subsidiaries
Management’s Financial Discussion and Analysis
therefore subject to CZMA consistency review by NYSDOS because it meets one of the two criteria for grandfathering established in the NYCMP. The court did not address the second criterion. Appeal to New York State’s highest court, the State Court of Appeals, was granted in June 2015 upon NYSDOS’s motion. Oral argument has not been scheduled.conjunction with NRC license renewal.
Second, in July 2012, Entergy filed a supplement to the Indian Point license renewal applications currently pending before the NRC. The supplement states that, based on applicable federal law and in lightFollowing a series of prior reviews by the State of New York,filings with 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. In July 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. In April 2013 the State of New York and Riverkeeper filed answers opposing Entergy’s motion. The State of New York also filed a cross-motion for declaratory order seeking confirmation that Indian Point had not been previously reviewed, and that only NYSDOS could conduct a CZMA review for NRC license renewal purposes. In April 2013 the NRC Staff filed answers recommending the ASLB deny both Entergy’s and the State of New York’s motions for declaratory order. In June 2013 the ASLB denied Entergy’s and the State of New York’s motions, without prejudice, on the ground that consultation on the matter of previous review among the NRC, Entergy (as applicant), and the State of New York had not taken place, as the ASLB determined to be required. In December 2013, NRC staff initiated consultation under federal CZMA regulations by serving on NYSDOS written questions related to whether Indian Point had been previously reviewed. In May 2014 the NYSDOS responded to questions the NRC staff submitted in December 2013. In July 2014, Entergy submitted comments on NYSDOS’s responses and NYSDOS filed a reply to those comments. Further submissions to the NRC staff with respect to the previous review issue were made by Entergy in November 2014 and by NYSDOS in December 2014. The NRC staff advised the ASLB in February 2015 that it iswas reviewing the information it hashad received regarding previous review and willwould provide further information when available.
Third, in December 2012, Entergy filed with NYSDOS a consistency determination explaining why Indian Point satisfies all applicable NYCMPNew York Coastal Management Program policies while noting that Entergy did not concede NYSDOS’s right to conduct a new CZMA review for Indian Point. In January 2013, NYSDOS notified Entergy that it deemed the consistency determination incomplete because it did not include the final version of a further supplement to the FSEIS that was targeted for subsequent issuance by NRC staff. In June 2013, NYSDOS notified Entergy that NYSDOS had received a copy of the final version of the FSEIS on June 20, 2013, and that NYSDOS’s review of the Indian Point consistency determination had begun that date. By a series of agreements, Entergy and NYSDOS agreed to extend NYSDOS’s deadline for concurring with or objecting to the Indian Point consistency certification to December 31, 2014. In November 2014, Entergy filed with the NRC and with NYSDOS a notice withdrawing the consistency certification. Entergy cited the NRC staff’s announcement two days earlier of its intent to issue in March 2016 a new FSEIS supplement addressing, among other things, new information concerning aquatic impacts. Entergy stated that unless the previous review or grandfathering issues were first and finally resolved in Entergy’s favor, Entergy intended to file a new consistency certification after the NRC issues the FSEIS supplement. That new consistency certification would initiate NYSDOS’s review process, would allow the FSEIS supplement to also be part of the record before NYSDOS, and, were NYSDOS to object to the new certification, would also be part of the record before the U.S. Secretary of Commerce on appeal.
NYSDOS disputed the effectiveness of Entergy’s November 2014 notice withdrawing the consistency certification. In December 2014, Entergy and NYSDOS executed an agreement intended to preserve the parties’ respective positions on withdrawal. The agreement provides, among other things, that if NYSDOS is correct about withdrawal not being effective, the parties will be deemed to have agreed to a stay of NYSDOS’s deadline for decision on the 2012 consistency certification to June 30, 2015. That agreementwhich was extended several times; upon expiration of the last extension, NYSDOS issued an objection onin November 6, 2015. On November 10, 2015, Entergy then filed with the National Oceanographic and Atmospheric Administration (NOAA), the agency within the U.S. Department of Commerce that has been delegated authority to act on CZMA appeals, a motion requesting a determination that Entergy’s November 2014 withdrawal notice was effective,
Entergy Corporation and the objection therefore invalid,Subsidiaries
Management’s Financial Discussion and Analysis
effective or, alternatively, an extension of the deadline for Entergy to file a notice of appeal and the consolidated record of proceedings which by law must be assembled by the federal licensing agency, here the NRC. OnIn November 25, 2015, after receiving papers in opposition
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
from NYSDOS, NOAA issued a letter (1) deferring until after the New York Court of Appeals ruled on grandfathering the determination whether Entergy’s withdrawal notice was effective, and (2) extending until that time Entergy’s deadline for filing a notice of appeal and the consolidated record. InIn January 2016, Entergy filed suit in the U.S. District Court for the Northern District of New York challenging NYDSOS’s November 6, 2015 CZMAthe New York State Department of Environmental Conservation’s objection to Entergy’s withdrawn Coastal Zone Management Act consistency certification on federal preemption grounds. Entergy’s complaint requestsrequested a determination that the objection, which cites nuclear safety concerns, is preempted and thus invalid.
ANO Damage, Outage, The NYSDOS filed a motion to dismiss Entergy’s lawsuit in March 2016, and NRC ReviewsEntergy filed its response in May 2016.
On March 31, 2013, duringOverview of Settlement
The Indian Point settlement requires New York State agencies to issue environmental certifications needed for license renewal and a scheduled refueling outage at ANO 1,renewed water discharge permit based on current plant configuration. It also requires the New York State Attorney General and Riverkeeper to withdraw their Track 2 contentions pending before the ASLB. In exchange, Entergy commits to cease commercial operation of Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021. Operations may be extended up to four years for each unit by mutual agreement of Entergy and New York State based on an exigent reliability need for Indian Point generation. See Note 14 to the financial statements for a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator outdiscussion of the turbine building. The collapse resulted in the death of an ironworkerimpairment and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claimsrelated charges associated with the ANO stator incident is available.settlement with New York State.
Entergy Arkansas is pursuing its optionsThe settlement establishes a detailed timeline for recovering damagesimplementation of steps necessary to allow Indian Point to receive renewed licenses and to implement Entergy’s commitment to shorten the life of the facility. Under that resultedtimeline, Indian Point expects to receive by the end of the first quarter 2017 a water quality certification and water discharge permit from the stator drop, including its insurance coverageNYSDEC and legal action. Entergy is a memberconcurrence from NYSDOS with a new CZMA consistency certification to be filed by Entergy. The settlement provides for issuance of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associatedsupplemental environmental analysis in May 2017 reflecting early shutdown. Consistent with the lifting apparatus failuresettlement, in January 2017 the NYSDEC Commissioner issued an order affirming the NYSDEC staff’s issuance of a final water quality certification and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s positiona final water discharge permit, and is evaluating its options for enforcing its rights underon the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due undersame day the policy. In July 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the ownerALJs terminated proceedings before them. Each of the heavy-lifting apparatus that collapsed, an engineering firm,water quality certification and CZMA concurrence will be filed with the NRC. In February 2017 the New York State Attorney General and Riverkeeper filed with the ASLB a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection withmotion to withdraw their responsibilitypending Track 2 contentions. There is no schedule for the stator drop.ASLB to act, but based on past practice the ASLB is expected to act by mid-2017. The NRC is not expected to be in a position to issue renewed licenses earlier than mid-2018, as its staff must first issue one, and potentially two, FSEIS.
Shortly after the stator incident, the NRC deployed an augmented inspection teamIn addition to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANOcontractually agreeing to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2,cease commercial operations early, in February 2017 Entergy filed with the NRC indicating furtheran amendment to its license renewal application changing the term of the requested licenses to coincide with the latest possible extension by mutual agreement based on exigent reliability needs: April 30, 2024 for Indian Point 2 and April 30, 2025 for Indian Point 3. If Entergy reasonably determines that these preliminary findingsthe NRC will treat the amendment other than as a routine amendment, Entergy may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.withdraw the amendment.
In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO was in the “degraded cornerstone column,” or column 3,Other provisions of the NRC’s reactor oversight process action matrix beginningsettlement include termination of all investigations of Indian Point by the first quarter 2014. Correctiveagencies signing the agreement, which include NYSDEC, NYSDOS, the New York State Department of Public Service, the New York State Department of Health, and the New York State Attorney General. The settlement recognizes the right of New York State agencies to pursue new investigations and enforcement actions in responsewith respect to new circumstances or existing conditions that become materially exacerbated.
Another provision of the NRC’s findings have been takensettlement obligates Entergy to establish a $15 million fund for environmental projects and remain ongoing at ANO.community support. Apportionment and allocation of funds to beneficiaries are to be determined by mutual agreement of New York State and Entergy. The settlement recognizes New York State’s right to perform an annual inspection of Indian Point, with scope and timing to be determined by mutual agreement.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held in October 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
In March 2015 the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also expects to incur approximately $50 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A much lesser amount of incremental expenses is expected to be ongoing annually after 2016.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel tracker would reallocate such cost shifts as between legacy customers of the companies on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs were recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.
In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. See Note 2 to the financial statements for further discussion of the business combination and related customer credits.
Human Capital Management Strategic Imperative
Entergy engaged in a strategic imperative intended to optimize the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted in the elimination of approximately 800 employee positions. Entergy incurred approximately $110 million and approximately $20 million in costs in 2013 and 2014, respectively, associated with this phase of human capital management, primarily implementation costs, severance expenses, pension curtailment losses, special termination benefits expense, and corporate property, plant, and equipment impairments. In December 2013, Entergy deferred for future recovery approximately $45 million of these costs, as approved by the APSC and the LPSC. See Note 2 to the financial statements for details of the deferrals and Note 13 to the financial statements for details of the restructuring charges.
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 increase in the debt to capital ratio for Entergy as of December 31, 20152016 is primarily due to the issuance of long-term debt in 2016 and a decrease in retained earnings. See Entergy’s Consolidated Statements of Changes in Equity for details of the decrease in retained earnings.
| | | | 2015 | | 2014 | 2016 | | 2015 |
| Debt to capital | 59.1 | % | | 57.4 | % | 64.8 | % | | 59.1 | % |
| Effect of excluding securitization bonds | (1.4 | %) | �� | (1.4 | %) | (1.0 | %) | | (1.4 | %) |
| Debt to capital, excluding securitization bonds (a) | 57.7 | % |
| 56.0 | % | 63.8 | % |
| 57.7 | % |
| Effect of subtracting cash | (2.7 | %) | | (2.8 | %) | (2.0 | %) | | (2.7 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 55.0 | % |
| 53.2 | % | 61.8 | % |
| 55.0 | % |
| |
| (a) | Calculation excludes the Arkansas, Louisiana, New Orleans and Texas securitization bonds, which are non-recourse to Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas, respectively. |
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 and commercial paper, 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 debt to capital 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 because the securitization bonds are non-recourse to Entergy, as more fully described in Note 5 to the financial statements. Entergy also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy’s financial condition because net debt indicates Entergy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
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, 2015.2016. To estimate future interest payments for variable rate debt, Entergy used the rate as of December 31, 2015.2016. The amounts below include payments on the Entergy LouisianaLouisiana’s Waterford 3 lease obligation and System EnergyEnergy’s Grand Gulf sale-leaseback transactions,transaction, which are included in long-term debt on the balance sheet.
| | Long-term debt maturities and estimated interest payments | | 2016 | | 2017 | | 2018 | | 2019-2020 | | after 2020 | | 2017 | | 2018 | | 2019 | | 2020-2021 | | after 2021 |
| | | (In Millions) | | (In Millions) |
| Utility | |
| $743 |
| |
| $890 |
| |
| $1,308 |
| |
| $1,978 |
| |
| $13,410 |
| |
| $1,021 |
| |
| $1,390 |
| |
| $1,219 |
| |
| $2,299 |
| �� |
| $14,758 |
|
| Entergy Wholesale Commodities | | 3 |
| | 2 |
| | 13 |
| | 2 |
| | 26 |
| | — |
| | 45 |
| | — |
| | — |
| | — |
|
| Parent and Other | | 89 |
| | 566 |
| | 66 |
| | 1,403 |
| | 690 |
| | 87 |
| | 87 |
| | 87 |
| | 1,287 |
| | 1,518 |
|
| Total | |
| $835 |
| |
| $1,458 |
| |
| $1,387 |
| |
| $3,383 |
| |
| $14,126 |
| |
| $1,108 |
| |
| $1,522 |
| |
| $1,306 |
| |
| $3,586 |
| |
| $16,276 |
|
Note 5 to the financial statements provides more detail concerning long-term debt outstanding.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in August 2020.2021. 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%0.225% of the undrawn 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, 20152016 was 1.98%2.23% on the drawn portion of the facility.
As of December 31, 2015,2016, amounts outstanding and capacity available under the $3.5 billion credit facility are:
| | Capacity (a) | | Borrowings | | Letters of Credit | | Capacity Available | | Borrowings | | Letters of Credit | | Capacity Available |
(In Millions) | | $3,500 | | $835 | | $9 | | $2,656 | | $700 | | $6 | | $2,794 |
A covenant in Entergy Corporation’s credit facility requires Entergy to maintain a consolidated debt ratio, as defined, 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 and expects to remain 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.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion. At December 31, 2015,2016, Entergy Corporation had $422$344 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 20152016 was 0.90%1.13%.
Capital lease obligations are a minimal part of Entergy’s overall capital structure. Following are Entergy’s payment obligations under those leases.
|
| | | | | | | | | |
| | 2016 | | 2017 | | 2018 | | 2019-2020 | | after 2020 |
| | (In Millions) |
| Capital lease payments | $5 | | $4 | | $4 | | $6 | | $25 |
|
| | | | | | | | | |
| | 2017 | | 2018 | | 2019 | | 2020-2021 | | after 2021 |
| | (In Millions) |
| Capital lease payments | $5 | | $4 | | $3 | | $6 | | $22 |
The capital leases are discussed in Note 10 to the financial statements.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 20152016 as follows:
|
| | | | | | | | | | |
Company | | Expiration Date | | Amount of Facility | | Interest Rate (a) | | Amount Drawn as of December 31, 20152016 | | Letters of Credit
Outstanding as of December 31, 20152016 |
| Entergy Arkansas | | April 20162017 | | $20 million (b) | | 1.92%2.02% | | — | | — |
| Entergy Arkansas | | August 20202021 | | $150 million (c) | | 1.92%2.02% | | — | | — |
| Entergy Louisiana | | August 20202021 | | $350 million (d) | | 1.67%2.02% | | — | | $3.16.4 million |
| Entergy Mississippi | | May 20162017 | | $10 million (e) | | 1.92%2.27% | | — | | — |
| Entergy Mississippi | | May 20162017 | | $20 million (e) | | 1.92%2.27% | | — | | — |
| Entergy Mississippi | | May 20162017 | | $35 million (e) | | 1.92%2.27% | | — | | — |
| Entergy Mississippi | | May 20162017 | | $37.5 million (e) | | 1.92%2.27% | | — | | — |
| Entergy New Orleans | | November 2018 | | $25 million (f) | | 2.17%2.52% | | — | — | $0.8 million |
| Entergy Texas | | August 20202021 | | $150 million (f)(g) | | 1.92%2.27% | | — | | $1.34.7 million |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
| |
(a) | The interest rate is the rate as of December 31, 20152016 that would be applied to outstanding borrowings under the facility. |
| |
(b) | Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option. |
| |
(c) | The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. |
| |
| (d) | The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. |
| |
| (e) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. |
| |
| (f) | The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing |
capacity of the facility.
| |
| (g) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. |
Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2015:2016:
| | | Company | | Amount of Uncommitted Facility | | Letter of Credit Fee | | Letters of Credit Issued as of December 31, 2015 | | Amount of Uncommitted Facility | | Letter of Credit Fee | | Letters of Credit Issued as of December 31, 2016 (a) |
| Entergy Arkansas | | $25 million | | 0.70% | |
| $1.0 | million | | $25 million | | 0.70% | |
| $1.0 | million |
| Entergy Louisiana | | $125 million | | 0.70% | |
| $17.1 | million | | $125 million | | 0.70% | |
| $5.7 | million |
| Entergy Mississippi | | $40 million | | 0.70% | |
| $6.0 | million | | $40 million | | 0.70% | |
| $7.1 | million |
| Entergy New Orleans | | $15 million | | 0.75% | |
| $1.4 | million | | $15 million | | 1.00% | |
| $6.2 | million |
| Entergy Texas | | $50 million | | 0.70% | |
| $9.4 | million | | $50 million | | 0.70% | |
| $14.7 | million |
| |
| (a) | As of December 31, 2016, letters of credit posted with MISO covered FTR exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of FTRs. |
In January 2015, Entergy Nuclear Vermont Yankee entered intohas a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60$100 million which expires in January 2018. AlsoAs of December 31, 2016, $45 million in January 2015,cash borrowings were outstanding under the credit facility. Entergy Nuclear Vermont Yankee entered intoalso has an uncommitted credit facility guaranteed by Entergy Corporation with a borrowing capacity of $85 million which expires in January 2018. As of December 31, 2016, there were no cash borrowings outstanding under the uncommitted credit facility. See Note 4 to the financial statements for additional discussion of the Vermont Yankee facilities.
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, results of operations, or cash flows. Following are Entergy’s payment obligations as of December 31, 20152016 on non-cancelable operating leases with a term over one year:
|
| | | | | | | | | |
| | 2016 | | 2017 | | 2018 | | 2019-2020 | | after 2020 |
| | (In Millions) |
| Operating lease payments | $78 | | $64 | | $53 | | $84 | | $80 |
|
| | | | | | | | | |
| | 2017 | | 2018 | | 2019 | | 2020-2021 | | after 2021 |
| | (In Millions) |
| Operating lease payments | $76 | | $70 | | $67 | | $93 | | $91 |
The operating leases are discussed in Note 10 to the financial statements.
Summary of Contractual Obligations of Consolidated Entities
| | | Contractual Obligations | | 2016 | | 2017-2018 | | 2019-2020 | | after 2020 | | Total | | 2017 | | 2018-2019 | | 2020-2021 | | after 2021 | | Total |
| | | (In Millions) | | (In Millions) |
| Long-term debt (a) | |
| $835 |
| |
| $2,845 |
| |
| $3,383 |
| |
| $14,126 |
| |
| $21,189 |
| |
| $1,108 |
| |
| $2,828 |
| |
| $3,586 |
| |
| $16,276 |
| |
| $23,798 |
|
| Capital lease payments (b) | |
| $5 |
| |
| $8 |
| |
| $6 |
| |
| $25 |
| |
| $44 |
| |
| $5 |
| |
| $7 |
| |
| $6 |
| |
| $22 |
| |
| $40 |
|
| Operating leases (b) (c) | |
| $78 |
| |
| $117 |
| |
| $84 |
| |
| $80 |
| |
| $359 |
| |
| $76 |
| |
| $137 |
| |
| $93 |
| |
| $91 |
| |
| $397 |
|
| Purchase obligations (d) | |
| $1,584 |
| |
| $2,684 |
| |
| $1,803 |
| |
| $4,165 |
| |
| $10,236 |
| |
| $1,435 |
| |
| $1,868 |
| |
| $1,392 |
| |
| $3,127 |
| |
| $7,822 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Lease obligations are discussed in Note 10 to the financial statements. |
| |
| (c) | Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations. |
| |
| (d) | 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. |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to the contractual obligations givenstated above, Entergy currently expects to contribute approximately $387.5$409 million to its pension plans and approximately $52.8$53 million to other postretirement plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017. 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 $1,347$978 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 20162017 through 2018.2019.
| | | Planned construction and capital investments | | 2016 | | 2017 | | 2018 | | 2017 | | 2018 | | 2019 |
| | | (In Millions) | | (In Millions) |
| Utility: | | | | | | | | | | | | |
| Generation | |
| $1,790 |
| |
| $1,155 |
| |
| $1,380 |
| |
| $1,390 |
| |
| $1,520 |
| |
| $1,465 |
|
| Transmission | | 715 |
| | 850 |
| | 725 |
| | 845 |
| | 860 |
| | 820 |
|
| Distribution | | 775 |
| | 810 |
| | 755 |
| | 755 |
| | 800 |
| | 805 |
|
| Other | | 270 |
| | 200 |
| | 185 |
| | 530 |
| | 360 |
| | 255 |
|
| Total | | 3,550 |
| | 3,015 |
| | 3,045 |
| | 3,520 |
| | 3,540 |
| | 3,345 |
|
| Entergy Wholesale Commodities | | 260 |
| | 235 |
| | 215 |
| | 230 |
| | 130 |
| | 60 |
|
| Total | |
| $3,810 |
| |
| $3,250 |
| |
| $3,260 |
| |
| $3,750 |
| |
| $3,670 |
| |
| $3,405 |
|
Planned construction and capital investments refer 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. In addition to routine capital projects, they also refer to amounts Entergy plans to spend on 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 include the following:following types of construction and capital investments:
Potential resource planning investments,Investments, including the UnionSt. Charles Power Station, acquisitionLake Charles Power Station, New Orleans Power Station, and Montgomery County Power Station, discussed below, and potential construction of additional generation.
Entergy Wholesale Commodities investments associated with specific investments such as component replacements, software and security, and dry cask storage, andstorage.
Investments in Entergy’s nuclear license renewal.
NRC post-Fukushima requirementsfleet. See “Nuclear Matters” below for the Utility and Entergy Wholesale Commodities nuclear fleets.
25discussion of this initiative.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Transmission spending to enhance reliability, reduce congestion, and enable economic growth.
Distribution spending to maintainenhance reliability and improve service to customers, including initial investment to support smart meter deployment.advanced metering.
For the next several years, the Utility’s owned generating capacity is projected to be adequate to meet MISO reserve requirements; however, in the longer-term additional supply resources will be needed, and its supply plan initiative will continue to seek to transform its generation portfolio with new 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.
St. Charles Power Station
In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. Discovery has begun in the proceeding.It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. Testimony has beenwas filed by LPSC staff and intervenors, with LPSC staff concluding that the construction of the project serves the public convenience and necessity. Three intervenors contendcontended that Entergy Louisiana hashad not established that construction of the project is in the public interest, claiming that the RFPrequest for proposal excluded consideration of certain resources that could be more cost effective, that the RFPrequest for proposal provided undue
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
preference to the self-build option, and that a 30-year capacity commitment iswas not warranted by current supply conditions. The RFPrequest for proposal independent monitor also filed testimony and a report affirming that the St. Charles Power Station was selected through an objective and fair RFPrequest for proposal that showed no undue preference to any proposal. An evidentiary hearing is scheduled forwas held in April 2016, and subject to regulatory approval byin July 2016 an ALJ issued a final recommendation that the LPSC full notice to proceedcertify that the construction of St. Charles Power Station is expected to bein the public interest. The LPSC issued its order approving certification of St. Charles Power Station in SummerDecember 2016. CommercialConstruction is in progress and commercial operation is estimated to occur by Summer 2019.mid-2019.
UnionLake Charles Power Station Purchase Agreement
In December 2014,November 2016, Entergy Arkansas, Entergy Gulf States Louisiana filed an application with the LPSC seeking certification that the public convenience and Entergy Texas entered into an asset purchase agreement to acquirenecessity would be served by the Unionconstruction of the Lake Charles Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P.nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The Unioncurrent estimated cost of the Lake Charles Power Station consistsis $872 million, including estimated costs of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuanttransmission interconnection and other related costs. A procedural schedule has been issued, with an evidentiary hearing scheduled for May and June 2017. Subject to timely approval by the agreement, Entergy Gulf States Louisiana would acquire twoLPSC and receipt of the power blocksother permits and a 50% undivided ownership interest in certain assets relatedapprovals, commercial operation is estimated to the facility, and Entergy Arkansas and Entergy Texas would each acquire one power block and a 25% undivided ownership interest in such related assets. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. Under the original terms of the asset purchase agreement, these included regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino antitrust law.occur by mid-2020.
In December 2014, Entergy Texas filed its application for Certificate of Convenience and Necessity (CCN) with the PUCT seeking one of the two necessary PUCT approvals of the acquisition. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the CCN filing. In July 2015, Entergy Texas withdrew its rate case and, together with other parties, filed a motion with the PUCT to dismiss Entergy Texas’s CCN application. In July 2015, the PUCT granted the motion to dismiss the CCN case. The power block originally allocated to Entergy Texas will be acquired by Entergy New Orleans. The acquisition by Entergy New Orleans replaces the power purchase agreement with Entergy Gulf States Louisiana that the City Council approved inPower Station
In June 2015. In August 2015,2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to proceed withconstruct the acquisitionNew Orleans Power Station, a 226 megawatt advanced combustion turbine in New Orleans, Louisiana, at the site of the power block and seeking approvalexisting Michoud generating facility, which facility was deactivated effective May 31, 2016. The current estimated cost of the recovery of the associated costs. In November 2015New Orleans Power Station is $216 million. A procedural schedule has been established with a decision expected no later than April 2017. Subject to timely approval by the City Council issued written resolutions and an order approving an agreement in principle between
Entergy Corporationother permits and Subsidiaries
Management’s Financial Discussion and Analysis
approvals, commercial operation is estimated to occur by late-2019. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In February 2017, Entergy New Orleans filed a motion to temporarily suspend the procedural schedule to allow for further analysis regarding its proposal, and City Council advisors providing that the purchase ofmotion was granted. A status conference is scheduled in March 2017.
Montgomery County Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest.Station
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery. Supplemental testimony was submitted in July 2015 explaining the reallocation of one of the power blocks to Entergy New Orleans and clarifying that Entergy Gulf States Louisiana would own 100% of the capacity and associated energy of two power blocks. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
In January 2015, Entergy Arkansas filed its application with the APSC for approval of the acquisition and cost recovery. A hearing was held in September 2015. In November 2015 the APSC issued an order conditionally approving the acquisition and requesting that Entergy Arkansas file compliance testimony reporting on two minor conditions. In January 2016, the APSC issued an order finding that Entergy Arkansas’s December 2015 compliance filing was substantially compliant with its November 2015 order. If the transaction closes on or before March 24, 2016, recovery of the costs to acquire Power Block 2 of the Union Power Station will be through Entergy Arkansas’s new base rates that will commence with the first billing cycle of April 2016. If the transaction closes after that date, the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.
In February 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed a notification and report form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act with the United States Department of Justice (DOJ) and Federal Trade Commission with respect to their planned acquisition of the Union Power Station. Union Power Partners, L.P. (UPP), the seller, also filed a notification and report form in February 2015.
In March 2015 the DOJ requested additional information and documentary material from each of the purchasing companies and UPP. Also in March 2015, UPP, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed an application with the FERC requesting authorization forPUCT seeking certification that the transaction. In April 2015, Entergy Arkansas, Entergy Gulf States Louisiana,public convenience and Entergy Texas made a filing withnecessity would be served by the FERC for approval of their proposed accounting treatmentconstruction of the amortization expenses relatingMontgomery County Power Station, a nominal 993 megawatt combined-cycle generating unit in Montgomery County, Texas on land adjacent to the acquisition adjustment. Filings were made withexisting Lewis Creek plant. The current estimated cost of the FERC in September 2015 replacing Entergy Texas with Entergy New Orleans as an applicant inMontgomery County Power Station is $937 million, including estimated costs of transmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the filings and providing supplemental information. In the FERC proceeding requesting authorization for the transaction, in December 2015, UPP, Entergy Arkansas, Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, and Entergy New Orleans filed their response to the FERC’s November 2015 request for additional information. The public comment period onproposal process, filed testimony and a report affirming that the December 2015 filing expiredMontgomery County Power Station was selected through an objective and fair request for proposal that showed no undue preference to any proposal. Discovery has commenced and a procedural schedule has been established for this proceeding, including an evidentiary hearing in January 2016. No protests were filed. The LPSC, City Council,May 2017. A PUCT decision regarding the application is expected by October 2017, pursuant to a Texas statute requiring the PUCT to issue an order regarding a certificate of convenience and APSC have filed submissions with the FERC urging the FERC to promptly consider and approve the transaction.
Closingnecessity within 366 days of the purchase is expectedfiling. Subject to be completed promptly followingtimely approval by the PUCT and receipt of FERC approval.other permits and approvals, commercial operation is estimated to occur by mid-2021.
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 earnings per share from the Utility operating segment and the Parent and Other portion of the business, financial strength, and future investment
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
opportunities. At its January 20162017 meeting, the Board declared a dividend of $0.85$0.87 per share. Entergy paid $612 million in 2016, $599 million in 2015, and $596 million in 2014 and $593 million in 2013 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 stock 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
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2015,2016, $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 ($1,3511,188 million as of December 31, 2015)2016);
securities issuances;
bank financing under new or existing facilities or commercial paper; and
sales of assets.
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 Articlesarticles of Incorporation or pertinent indentures and various other agreementsincorporation 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, 2015, 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 2017. Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016.June 2018. Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its respective nuclear fuel company variable interest entity. In addition to borrowings from commercial banks, the Registrant Subsidiaries may also borrow from 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 short-term borrowing limits. See Notes 4 and 5 to the financial statements for further discussion of Entergy’s borrowing limits, authorizations, and amounts outstanding.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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. In January 2013, Entergy Louisiana drew $252 million from its funded storm reserve escrow accounts. In April 2013, Entergy Louisiana filed a joint application withJune 2014 the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Louisiana requested an LPSC determination that $321.5 million in system restoration costs were prudently incurred. In May 2013, 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 Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of the company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amountquantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred ($290.8incurred; (ii) determined $290 million for Entergy Louisiana); (ii) determineas the level of storm reserves to be re-established ($290 million for Entergy Louisiana);re-established; (iii) authorizeauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grantgranted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Louisiana issued two series totaling $300 million See Note 2 to the financial statements for a discussion of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $314.85 million inissuance of bonds under Act 55 of the Louisiana Legislature. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, 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 $1.75 billion.
Entergy 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 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 and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.
In May 2015, the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for a discussion of the July 2015 issuance of the securitization bonds.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Cash Flow Activity
As shown in Entergy’s Consolidated Statements of Cash Flows, cash flows for the years ended December 31, 2016, 2015, 2014, and 20132014 were as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Millions) | (In Millions) |
| Cash and cash equivalents at beginning of period |
| $1,422 |
| |
| $739 |
| |
| $533 |
|
| $1,351 |
| |
| $1,422 |
| |
| $739 |
|
| |
|
| | | | |
|
| | | | |
| Net cash provided by (used in): | |
| | |
| | |
| |
| | |
| | |
|
| Operating activities | 3,291 |
| | 3,890 |
| | 3,189 |
| 2,999 |
| | 3,291 |
| | 3,890 |
|
| Investing activities | (2,609 | ) | | (2,955 | ) | | (2,602 | ) | (3,850 | ) | | (2,609 | ) | | (2,955 | ) |
| Financing activities | (753 | ) | | (252 | ) | | (381 | ) | 688 |
| | (753 | ) | | (252 | ) |
| Net increase (decrease) in cash and cash equivalents | (71 | ) | | 683 |
| | 206 |
| (163 | ) | | (71 | ) | | 683 |
|
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $1,351 |
| |
| $1,422 |
| |
| $739 |
|
| $1,188 |
| |
| $1,351 |
| |
| $1,422 |
|
Operating Activities
2016 Compared to 2015
Net cash provided by operating activities decreased by $292 million in 2016 primarily due to:
a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to 2015. See Note 2 to the financial statements for a discussion of fuel and purchased power cost recovery;
lower Entergy Wholesale Commodities net revenue in 2016 as compared to 2015, as discussed previously; and
an increase of $83 million in interest paid in 2016 as compared to 2015 primarily due to an interest payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets and an increase in interest expense primarily due to 2016 net debt issuances by various Utility operating companies, partially offset by a decrease in interest paid in 2016 on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of a beneficial interest
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
in the Waterford 3 leased assets and for details of the Grand Gulf lease obligation. See Note 5 to the financial statements for a discussion of long-term debt.
The decrease was partially offset by:
higher Utility net revenues in 2016 as compared to 2015, as discussed above;
proceeds of $102 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for discussion of the spent nuclear fuel litigation;
a decrease of $46 million in spending on nuclear refueling outages in 2016 as compared to 2015; and
a decrease of $19 million in spending related to the shutdown of Vermont Yankee, which ceased power production in December 2014.
2015 Compared to 2014
Net cash provided by operating activities decreased by $599 million in 2015 primarily due to:
lower Entergy Wholesale Commodities net revenues in 2015 as compared to 2014, as discussed previously;
proceeds of $310 million received from the Louisiana Utilities Restoration Corporation in August 2014 as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” above for a discussion of the Act 55 storm cost financing;
spending of $78 million in 2015 on activities related to the decommissioning of Vermont Yankee, which ceased power production in December 2014;
an increase of $52 million in interest paid in 2015 primarily due to an increase in interest paid on the Grand Gulf sale-leaseback obligation. See Note 10 to the financial statements for details of the Grand Gulf sale-leasebacklease obligation;
an increase in spending of $48 million in 2015 related to Vermont Yankee, including the severance and retention payments accrued in 2014 and defueling activities that took place after the plant ceased power production in December 2014; and
an increase in income tax payments of $26 million primarily due to payments made in 2015 for the final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the finalized tax and interest computations for the 2006-2007 IRS audit.
The decrease was partially offset by:
an increase indue to the timing of recovery of fuel and purchased power costs in 2015;
higher Utility net revenues in 2015 as compared to 2014, as discussed above; and
a decrease of $46 million in storm spending in 2015 as compared to 2014.
Investing Activities
2016 Compared to 2015
Net cash flow used in investing activities increased by $1,241 million in 2016 primarily due to:
the purchase of the Union Power Station for approximately $949 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 14 to the financial statements for further discussion of the sale; and
an increase of $279 million in construction expenditures, primarily in the Utility business. The increase in construction expenditures in the Utility business is primarily due to an increase of $114 million in transmission construction expenditures primarily due to an overall higher scope of work performed on transmission projects
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
2014 Compared to 2013
Net cash provided by operating activities increased by $701in 2016 as compared to 2015, an increase of $106 million in 2014nuclear construction expenditures primarily due to:
to a higher scope of work on various nuclear projects in 2016 as compared to 2015, an increase of $95 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016, an increase of $79 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015 and higher storm restoration spending in 2016, and an increase of $65 million in information technology construction expenditures due to various information technology projects and upgrades in 2016. The increase was partially offset by a decrease of $148 million in spending related to compliance with NRC post-Fukushima requirements in the Utility and Entergy Wholesale Commodities and Utility net revenues in 2014 as compared to 2013, as discussed previously;
proceeds of $310 million received from the LURC in August 2014 as a result of the Louisiana Act 55 storm cost financings. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financings;
$58 million margin deposits made by Entergy Wholesale Commodities in 2013;
a decrease in income tax payments of $50 million in 2014 compared to 2013 primarily due to state income tax effects of the settlement of the 2004-2005 IRS audit paid in 2013; and
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed previously.businesses.
The increase was partially offset by:
a decrease of $179 million in nuclear fuel purchases due to 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;
an increase of $236$151 million in pension contributionsproceeds received from the DOE in 2014, partially offset by a decrease of $38 million in lump sum retirement payments out of the non-qualified pension plan in 20142016 as compared to 2013.the prior year resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See “Critical Accounting Estimates” below and Note 118 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
proceeds of $72 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;fuel litigation;
an increasea $71 million NYPA value sharing payment in 2015. See Note 14 to the financial statements for further discussion of $44 million in spending on nuclear refueling outages in 2014 as compared to 2013;Entergy’s NYPA value sharing agreements; and
an increasethe deposit of $25$64 million into Entergy New Orleans’s storm reserve escrow accounts in storm restoration spending in 2014.
Investing Activities2015.
2015 Compared to 2014
Net cash flow used in investing activities decreased by $346 million in 2015 primarily due to:
proceeds of approximately $490 million from the sale in December 2015 of Rhode Island State Energy Center. See Note 1514 to the financial statements for further discussion of the sale;
the deposit of a total of $64 million into Entergy New Orleans’s storm reserve escrow accounts in 2015 compared to the deposit of a total of $268 million into Entergy Louisiana’s storm reserve escrow accounts in 2014;
$58 million in disbursements from the Vermont Yankee decommissioning trust funds to Entergy in 2015; and
a decrease in nuclear fuel purchases due to 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.
The decrease was partially offset by:
an increase in construction expenditures primarily due to an overall higher scope of work on various projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements, partially offset by a decrease in storm restoration spending and a decrease in spending on the Ninemile Unit 6 project;
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and
a decrease of $16 million in insurance proceeds primarily due to $13 million received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant eventin September 2013; and $12
$12 million received in 2015 for property damages related to the generator stator incident at ANO compared to $37 million received in 2014 for property damages related to the generator stator incident at ANO. See Note 8 to the financial statements for a discussion of the ANO stator incident.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
stator incident at ANO.Financing Activities
2016 Compared to 2015
Entergy’s financing activities provided $688 million of cash for 2016 compared to using $753 million of cash for 2015 primarily due to the following activity:
long-term debt activity providing approximately $1,489 million of cash in 2016 compared to providing $41 million of cash in 2015. Included in the long-term debt activity is net repayments of borrowings of $135 million in 2016 compared to net borrowings of $140 million in 2015 on the Entergy Corporation long-term credit facility;
the issuance of $110 million of preferred stock in 2015. See Note 86 to the financial statements for further discussion;
$100 million of common stock repurchased in 2015, as discussed above;
a net increase of $41 million in 2016 in short-term borrowings by the nuclear fuel company variable interest entities; and
an increase of $21 million in the repurchase or redemption of preferred stock. In September 2015, Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and Entergy Gulf States Louisiana repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the Baxter Wilson plant eventcombination. In 2016, Entergy Arkansas redeemed its $75 million of 6.45% Series preferred stock and the ANO stator incident.
2014 Compared to 2013
Net cash used in investing activities increased by $353its $10 million in 2014 primarily due to:
the deposit of a total6.08% Series preferred stock and Entergy Mississippi redeemed its $30 million of $276 million into storm reserve escrow accounts in 2014, primarily by Entergy Louisiana. See “Hurricane Isaac” above for a discussion of storm reserve escrow account replenishments in 2014;
the withdrawal of a total of $260 million from storm reserve escrow accounts in 2013, primarily by Entergy Louisiana, after Hurricane Isaac. See “Hurricane Isaac” above for discussion of storm reserve escrow account withdrawals;
proceeds of $140 million from the sale in November 2013 of Entergy Solutions District Energy. See Note 15 to the financial statements for further discussion of the sale;
proceeds of $21 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel; and
an increase in nuclear fuel purchases due to 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.
The increase was partially offset by:
a decrease in construction expenditures, primarily in the Utility business, including a decrease in spending on the Ninemile 6 project and spending in 2013 on the generator stator incident at ANO, partially offset by an increase in storm restoration spending;
a change in collateral deposit activity, reflected in the “Decrease (increase) in other investments” line on the Consolidated Statements of Cash Flows, as Entergy received net deposits of $47 million in 2014 and returned net deposits of $88 million in 2013. Entergy Wholesale Commodities’ forward sales contracts are discussed in the “Market and Credit Risk Sensitive Instruments” section below; and
$37 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above.
Financing Activities6.25% Series preferred stock.
2015 Compared to 2014
Net cash flow used in financing activities increased $501 million in 2015 primarily due to:
long-term debt activity providing approximately $41 million of cash in 2015 compared to providing $777 million of cash in 2014. Included in the long-term debt activity is $140 million in 2015 and $440 million in 2014 for the repayment of borrowings on the Entergy Corporation long-term credit facility;
a decrease of $171 million in treasury stock issuances in 2015 primarily due to a larger amount of previously repurchased Entergy Corporation stock issued in 2014 to satisfy stock option exercises;
a net decrease of $154 million in 2015 in short-term borrowings by the nuclear fuel company variable interest entities; and
the repurchase or redemption of $94 million of preferred membership interests in 2015. Entergy Louisiana redeemed its $100 million 6.95% Series preferred membership interests, of which $16 million was owned by Entergy Louisiana Holdings, an Entergy subsidiary, and repurchased its $10 million Series A 8.25% preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
net repayments of $62 million of commercial paper in 2015 compared to net repayments of $561 million of commercial paper in 2014;
the issuance of $110 million of preferred stock in 2015. See Note 6 to the financial statements for further discussion;discussion of preferred stock issuances; and
a decrease of $83 million of common stock repurchased in 2015 as compared to 2014.2014, as discussed above.
2014 Compared to 2013
Net cash flow used in financing activities decreased by $129 million in 2014 primarily due to:32
Entergy Corporation repaid $561 million of commercial paper in 2014 and issued $380 million in 2013;Subsidiaries
an increase of $112 million in 2014 compared to a decrease of $129 million in 2013 in short-term borrowings by the nuclear fuel company variable interest entities;Management’s Financial Discussion and Analysis
the repurchase of $183 million of Entergy common stock in 2014; and
an increase of $170 million in treasury stock issuances in 2014 primarily due to a larger amount of previously repurchased Entergy Corporation common stock issued in 2014 to satisfy stock option exercises.
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. See Note 5 to the financial statements for details of long-term debt.
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 | | 9.25%-10.25% - 10.25% |
| Entergy Louisiana | | 9.15%-10.75% - 10.75% Electric; 9.45%-10.45% - 10.45% Gas |
| Entergy Mississippi | | 10.07%9.89% - 11.97% |
| 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.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Federal Regulation
Entergy’s Integration Into the MISO Regional Transmission Organization
In April 2011, Entergy announced that each of the Utility operating companies proposed to join the MISO RTO, an RTO operating in several U.S. states and also in Canada. On December 19, 2013, the Utility operating companies completed their planned integration into the MISO RTO. Becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities. With the Utility operating companies fully integrated as members, however, MISO assumed control of transmission planning and congestion management and, through its Day 2 market, MISO provides 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 Utility operating companies obtained from each of their 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. See also “System Agreement - Utility Operating Company Notices of Termination of System Agreement Participation” below.
Beginning in 2011 the Utility operating companies and the MISO RTO began submitting various filings with the FERC that contained many of the rates, terms and conditions that would govern the Utility operating companies’ integration into the MISO RTO. The Utility operating companies and the MISO RTO received the FERC orders necessary for those companies to integrate into the MISO RTO consistent with the approvals obtained from the Utility operating companies’ retail regulators, although some proceedings remain pending at the FERC.
In January 2013, Occidental Chemical Corporation filed with the FERC a petition for declaratory judgment and complaint against MISO 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 the Public Utility Regulatory Policies Act (PURPA) and the FERC’s implementing regulations. In February 2014, Occidental also filed a petition for enforcement with the FERC against the LPSC. Occidental’s petition for enforcement alleges that the LPSC’s January 2014 order, which approved Entergy Louisiana’s application for modification of Entergy’s methodology for calculating avoided cost rates paid to QFs, is inconsistent with the requirements of PURPA and the FERC’s regulations implementing PURPA. In April 2014 the FERC issued a “Notice Of Intent Not To Act At This Time” with respect to Occidental’s petition for enforcement against the LPSC. The FERC concluded that Occidental’s petition for enforcement largely raises the same issues as those raised in the January 2013 complaint and petition for declaratory order that Occidental filed against MISO, and that the two proceedings should be addressed at the same time. The FERC reserved its ability to issue a further order or to take further action at a future date should it find that doing so is appropriate. In January 2016, in a separate proceeding, the FERC issued an order granting the Utility operating companies’ petition to terminate the requirement that they enter into new obligations or contracts with QFs with net capacity in excess of 20 MW, including Occidental’s Taft QF, effective October 2015. The FERC denied without prejudice the petition as it relates to Dow Chemical Company’s Plaquemine QF.
In April 2014, Occidental filed a complaint in federal district court for the Middle District of Louisiana against the LPSC and Entergy Louisiana that challenges the January 2014 order issued by the LPSC on grounds similar to those raised in the 2013 complaint and 2014 petition for enforcement that Occidental previously filed at the FERC. The district court complaint also seeks damages from Entergy Louisiana and a declaration from the district court that in pursuing the January 2014 order Entergy Louisiana breached an existing agreement with Occidental and an implied covenant of good faith and fair dealing. In January 2015 the district court granted Entergy Louisiana’s motion to stay the district court proceeding, pending a decision from the FERC relating to the MISO tariff and market rules that are underlying Occidental’s district court complaint. In January 2015, Occidental filed a motion for reconsideration in the district court and also filed a notice of appeal to the U.S. Fifth Circuit Court of Appeals. In February 2015 the district court denied the motion for reconsideration as moot, finding it lacked jurisdiction to consider the motion because Occidental had sought an appeal to the U.S. Fifth Circuit Court of Appeals.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In January 2016 the U.S. Fifth Circuit Court of Appeals vacated the district court’s stay order and remanded the case to the district court to enter a new order staying the proceedings for a period of 180 days to allow the FERC the opportunity to rule on the MISO tariff and market rules that are underlying Occidental’s district court complaint. If the FERC fails to act within that 180 day period, then the district court may extend the deadline if (1) good cause is shown regarding the lack of FERC action, and (2) the delay would not irreparably harm Occidental’s rights. The district court entered a new stay order in January 2016.
In February 2013, Entergy Services, on behalf of the Utility operating companies, made a filing with the FERC requesting to adopt the standard Attachment O formula rate template used by transmission owners to establish transmission rates within MISO. The filing proposed four transmission pricing zones for the Utility operating companies, one for Entergy Arkansas, one for Entergy Mississippi, one for Entergy Texas, and one for Entergy Louisiana and Entergy New Orleans. In June 2013 the FERC issued an order accepting the use of four transmission pricing zones and set for hearing and settlement judge procedures those issues of material fact that FERC decided could not be resolved based on the existing record. Several parties, including the City Council, filed requests for rehearing of the June 2013 order. In February 2014 the FERC issued an order addressing the rehearing requests. Among other things, the FERC denied rehearing and affirmed its prior decision allowing the four transmission pricing zones for the Utility operating companies in MISO. The FERC granted rehearing and set for hearing and settlement judge proceedings certain challenges of MISO’s regional through and out rates. In March 2014 certain parties filed a request for rehearing of the FERC’s February 2014 order on issues related to MISO’s regional through and out rates. In February 2014 and April 2014 various parties appealed the FERC’s June 2013 and February 2014 orders to the U.S. Court of Appeals for the D.C. Circuit where the appeals have been consolidated for further proceedings. In July 2015, as amended in August and October 2015, Entergy Services, on behalf of the Utility operating companies, filed a settlement at the FERC resolving all issues relating to the Utility operating companies’ Attachment O transmission rates in MISO except for challenges to MISO’s regional through and out rates. In October 2015 the presiding judge certified the settlement as contested to the FERC due to comments opposing the settlement filed by the same parties that have raised issues related to MISO’s through and out rates. The settlement is pending before the FERC.
In May 2015 several parties filed a complaint against MISO related to certain charges for transmission service provided by MISO to them when their point-to-point service under the Entergy open access transmission tariff was transitioned to the MISO tariff in December 2013. The complainants request that the FERC order refunds for alleged overcharges since December 2013, or alternatively that the FERC institute a proceeding under Section 206 of the Federal Power Act to address the legality of transmission applicable rates and establish a different fifteen-month refund period from the period established in the FERC’s February 2014 order. In June 2015, another party filed a similar complaint against MISO. MISO filed answers to both complaints asking the FERC to dismiss the complaints, and Entergy filed protests in support of MISO’s answers. Also in June 2015 the FERC issued an order denying rehearing of certain determinations in the February 2014 order regarding MISO’s regional through and out rates. In October 2015 the FERC issued an order denying the complaints filed in May and June 2015, finding that MISO did not violate its tariff and the justness and reasonableness of the rates referenced in the complaints are already being addressed in the proceeding initiated in February 2014, thus rendering the complaints duplicative. The proceeding initiated in February 2014 is being held in abeyance pending settlement discussions.
System Agreement
The FERC regulates wholesale sales of electricity rates (including Entergy Utility intrasystem energy allocations pursuant to the System Agreement) and interstate transmission of electricity, as well asincluding 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 current return on equity under the Unit Power Sales Agreement is 10.94%. Prior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), 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 iswas 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
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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.
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. The LPSC, MPSC, PUCT, and City Council filed protests at the FERC regarding the amendments 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. In December 2013 the FERC issued an order accepting the revisions filed in November 2012, subject to a further compliance filing and other conditions. Entergy Services made the requisite compliance filing in February 2014 and the FERC accepted the compliance filing in November 2015. In the November 2015 order, the FERC required Entergy Services to file a refund report consisting of the results of the intra-system bill rerun from December 19, 2013 through November 30, 2015 calculating the use of an energy-based allocator to allocate losses, ancillary services charges and credits, and uplift charges and credits to load of each participating Utility operating company. The filing shows the following payments and receipts among the Utility operating companies:
|
| |
| Payments
(Receipts)
|
| (In Millions) |
Entergy Louisiana | ($6.3) |
Entergy Mississippi | $4 |
Entergy New Orleans | $0.4 |
Entergy Texas | $1.9 |
In the December 2013 order, the FERC set one issue for hearing involving a settlement with Union Pacific regarding certain coal delivery issues. Consistent with the decisions described above, Entergy Arkansas’s participation in the System Agreement terminated effective December 18, 2013. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding have filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision and the matter is pending before the FERC.
Utility Operating Company Notices of Termination of System Agreement Participation
Consistent with their written notices of termination delivered in December 2005 and November 2007, respectively, Entergy Arkansas and Entergy Mississippi filed with the FERC in February 2009 their notices of cancellation to terminate their participation in the System Agreement, effective December 18, 2013 and November 7, 2015, respectively. 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. Appeals by the LPSC and the City Council were denied in 2012 and 2013. Effective December 18, 2013, Entergy Arkansas ceased participating in the System Agreement. Effective November 7, 2015, Entergy Mississippi ceased participating in the System Agreement.
In keeping with their prior commitments and after a careful evaluation of the basis for and continued reasonableness of the 96-month System Agreement termination notice period, the Utility operating companies filed with the FERC in October 2013 to amend the System Agreement changing the notice period for an operating company
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
to terminate its participation in the System Agreement from 96 months to 60 months. Subsequent to that filing, Entergy Texas and Entergy Louisiana separately provided notice to terminate their participation in the System Agreement.
In December 2014 the FERC issued an order setting the proposed amendment changing the notice period from 96 months to 60 months for settlement judge and hearing procedures. In August 2015, Entergy Services filed a settlement in the FERC dockets addressing the notice period for exiting the System Agreement, including the pending notices of withdrawal filed by Entergy Louisiana and Entergy Texas. The settlement was expressly conditioned on obtaining the necessary FERC and state and local regulatory approvals. By November 2015, all necessary state and local regulatory approvals had been obtained, and in December 2015 the FERC issued an order approving the settlement.
Under the settlement, the System Agreement will terminate at the end of August 2016 as to all parties remaining as of that date. The purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana will terminate, effective with System Agreement termination. Similarly, the PPA between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also will terminate. Currently, the jurisdictional separation plan PPAs are the means by which Entergy Texas receives payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset.federal courts. See Note 2 to the financial statements for discussion of the decision to write offSystem Agreement proceedings and a complaint filed with the Spindletop regulatory asset.FERC challenging System Energy’s return on equity.
The settlement also provides that Entergy New Orleans will be established as a separate transmission pricing zone in MISO effective with System Agreement termination, and that Entergy New Orleans will make payments to Entergy Louisiana in the amount of $2.2 million annually for a period of 15 years. Entergy New Orleans will obtain an option to participate in a portion of certain future Amite South CCGT resources that may be procured by Entergy Louisiana, subject to certain conditions and restrictions. If Entergy New Orleans acquires Power Block 1 of the Union Power Station and obtains full deliverability of the resource, this option will terminate. Entergy New Orleans will also pursue investment in certain new generating resources located in New Orleans.
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.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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 1716 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 outstanding indebtedness. 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 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 regulators, the Utility operating companies use commodity and financial instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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. Entergy is also exposed to a potential demand on liquidity due to credit support requirements within its supply or sales agreements.
Commodity Price Risk
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 also 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, and 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, and sensitivities are provided in the table below to show potential variations. The sensitivities may not reflect the total maximum upside potential from higher market prices. The information contained in the following table 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, 2015.2016.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Wholesale Commodities Nuclear Portfolio
| | | | | 2016 | | 2017 | | 2018 | | 2019 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
| Energy | | | | | | | | | |
| Percent of planned generation under contract (a): | | | | | | | | | |
| Unit-contingent (b) | | 65% | | 53% | | 21% | | 26% | | 87% | | 66% | | 5% | | —% | | —% |
| Firm LD (c) | | 41% | | 10% | | —% | | —% | | 10% | | —% | | —% | | —% | | —% |
| Offsetting positions (d) | | (20%) | | —% | | —% | | —% | | (10%) | | (10%) | | —% | | —% | | —% |
| Total | | 86% | | 63% | | 21% | | 26% | | 87% | | 56% | | 5% | | —% | | —% |
| Planned generation (TWh) (e) (f) | | 36 | | 28 | | 29 | | 26 | | 27.3 | | 26.7 | | 18.8 | | 11.7 | | 2.9 |
| Average revenue per MWh on contracted volumes: | | | | | | | | | |
| Minimum | | $45 | | $46 | | $56 | | $57 | | $43.7 | | $36.4 | | $53.2 | | $— | | $— |
| Expected based on market prices as of December 31, 2015 | | $46 | | $46 | | $56 | | $57 | |
| Expected based on market prices as of December 31, 2016 | | | $44.0 | | $36.4 | | $53.2 | | $— | | $— |
| Sensitivity: -/+ $10 per MWh market price change | | $45-$47 | | $46-$48 | | $56 | | $57 | | $43.8-$44.5 | | $34.9-$37.8 | | $53.2 | | $— | | $— |
| | | |
| Capacity | | | | | | | | | |
| Percent of capacity sold forward (g): | | | | | | | | | |
| Bundled capacity and energy contracts (h) | | 17% | | 21% | | 22% | | 25% | | 22% | | 10% | | —% | | —% | | —% |
| Capacity contracts (i) | | 26% | | 19% | | 20% | | 9% | | 31% | | 23% | | 12% | | —% | | —% |
| Total | | 43% | | 40% | | 42% | | 34% | | 53% | | 33% | | 12% | | —% | | —% |
| Planned net MW in operation (f) | | 4,406 | | 3,638 | | 3,568 | | 3,167 | |
| Average revenue under contract per kW per month(applies to capacity contracts only) | | $3.3 | | $5.6 | | $9.4 | | $11.1 | |
| Planned net MW in operation (average) (f) | | | 3,568 | | 3,365 | | 2,356 | | 1,384 | | 347 |
| Average revenue under contract per kW per month (applies to capacity contracts only) | | | $4.9 | | $9.4 | | $11.1 | | $— | | $— |
| | | |
Total Nuclear Energy and Capacity Revenues | | | | | | | | | |
| Expected sold and market total revenue per MWh | | $48 | | $49 | | $49 | | $51 | | $50.6 | | $44.6 | | $44.4 | | $43.6 | | $48.1 |
| Sensitivity: -/+ $10 per MWh market price change | | $46-$51 | | $45-$53 | | $42-$57 | | $43-$58 | | $49.5-$52.0 | | $39.3-$49.9 | | $34.9-$53.9 | | $33.6-$53.6 | | $38.1-$58.1 |
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| (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. Positions that are not classified as hedges are netted in the planned generation under contract. |
| |
| (b) | Transaction under which power is supplied from a specific generation asset; if the asset is not operating, the seller is generally not liable to buyer for any damages. Certain unit-contingent sales include a guarantee of availability. Availability guarantees provide 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. |
| |
| (c) | 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. This also includes option transactions that may expire without being exercised. |
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| (d) | Transactions for the purchase of energy, generally to offset a Firm LD transaction. |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
| |
| (e) | Amount of output expected to be generated by Entergy Wholesale Commodities resources considering plant operating characteristics, outage schedules, and expected market conditions that affect dispatch. |
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| (f) | Assumes the sale of FitzPatrick to Exelon in the second quarter 2017, planned shutdown of Palisades on October 1, 2018, planned shutdown of Pilgrim on May 31, 2019, planned shutdown of Indian Point 2 on April 30, 2020, and planned shutdown of Indian Point 3 on April 30, 2021. Assumes NRC license renewals for plants with NRC license renewal applications in process. Assumes shutdown of FitzPatrick at the end of January 2017 , shutdown of Pilgrim June 1, 2019, and uninterrupted normal operation at remaining 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 now operating under its period of |
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating under its period of extended operations while its application is pending). For a discussion regarding the shutdown of the FitzPatrick and Pilgrim plants, see Note 1 to the financial statements. extended operations while its application is pending) and Indian Point 3 (December 2015 and now operating under its period of extended operations while its application is pending). For a discussion regarding the planned sale of the FitzPatrick plant and planned shutdown of the Palisades, Pilgrim, Indian Point 2, and Indian Point 3 plants, see “Entergy Wholesale Commodities Exit from the Merchant Power Business” above. 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.
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| (g) | Percent of planned qualified capacity sold to mitigate price uncertainty under physical or financial transactions. |
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| (h) | A contract for the sale of installed capacity and related energy, priced per megawatt-hour sold. |
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| (i) | A contract for the sale of an installed capacity product in a regional market. |
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| (j) | Includes assumptions on converting a portion of the portfolio to contracted with fixed price cost or discount and excludes non-cash revenue from the amortization of the Palisades below-market purchased power agreement, mark-to-market activity, and service revenues. |
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 income of $99$37 million in 20162017 and would have had a corresponding effect on pre-tax income of $107$99 million in 2015.2016. A negative $10 per MWh change in the annual average energy price in the markets based on the respective year-end market conditions, planned generation volumes, and hedged positions, would have a corresponding effect on pre-tax income of ($74)31) million in 20162017 and would have had a corresponding effect on pre-tax income of ($73)74) million in 2015.2016.
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 paid 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’s output was due by January 15 of the following year. Entergy recorded the liability for payments to NYPA as power is generated and sold by Indian Point 3 and FitzPatrick. In 2014, and 2013, Entergy Wholesale Commodities recorded a liability of approximately $72 million for generation during each of those years.that year. 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 credit support to secure its obligations under the agreements. The Entergy subsidiary is required to provide credit support based upon the difference between the current market prices and contracted power prices in the regions where Entergy Wholesale Commodities sells power. The primary form of credit support to satisfy these requirements is an Entergy Corporation guaranty. Cash and letters of credit are also acceptable forms of credit support. At December 31, 2015,2016, based on power prices at that time, Entergy had liquidity exposure of $142$128 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $14$8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2015,2016, Entergy would have been required to provide approximately $52$57 million of additional cash or letters of credit under some of the agreements. As of December 31, 2015,2016, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously posted collateral from counterparties, would increase by $98$238 million for a $1 per MMBtu increase in gas prices in both the short-and long-term markets.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
As of December 31, 2015,2016, substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants through 20192021 is with counterparties or their guarantors that have public investment grade credit ratings.
Nuclear Matters
AfterIn 2016, Entergy conducted a comprehensive evaluation of the Entergy nuclear incidentfleet and determined that it is necessary to increase investments in Japan resulting fromits nuclear plants to position the March 2011 earthquake and tsunami, the NRC established a task forcefleet to conduct a review of processes and regulations relating to nuclear facilities in the United States. The
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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 March 2012. The three orders require U.S. nuclear operators to undertake plant modifications and perform additional analyses thatmeet its operational goals. These investments will among other things, result in increased operating and capital costs associated with operating Entergy’s nuclear plants.plants going forward. The NRC,preliminary estimates of the increase to planned capital costs for 2017 through 2019 identified through and associated with input fromthis initiative are estimated to be$870 million for Utility. The preliminary estimates indicate that the industry, is continuingcapital costs identified through this initiative for Entergy Wholesale Commodities are expected to determinehave a minimal effect on Entergy’s preliminary capital investment plan estimate for 2017 through 2019. The current estimates of the specific actions required by the orders. Entergy’s estimated capital expenditures for 2016costs identified through 2018 for complying with the NRC ordersthis initiative are included in the planned construction and otherEntergy’s preliminary capital investments estimatesinvestment plan estimate for 2017 through 2019 given in “Liquidity“Liquidity and Capital Resources - Capital Expenditure Plans and Other Uses of Capital”Capital” above.
In June 2012 The increase to planned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $125 million in 2017 for Utility, with a similar level of expenses expected to continue going forward, and approximately $25 million in 2017 for Entergy Wholesale Commodities, with a similar level of expenses expected to continue going forward while 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 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 the 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 ofmerchant nuclear plants including Grand Gulfare operating. In addition, nuclear refueling outage expenses are expected to increase going forward for both Utility and Indian Point 2 and 3. In August 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. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spent nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challenge to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.Entergy Wholesale Commodities.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
ANO
See “ANO Damage, Outage, and NRC Reviews” above and Note 8 to the financial statements for discussion of the NRC’s decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4)column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.
Pilgrim
See Note 8 to the financial statements for discussion of the NRC’s decision in September 2015 to place Pilgrim in Column 4 of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures.
Indian Point
During the scheduled refueling and maintenance outage at Indian Point Unit 2 in the first quarter 2016, comprehensive inspections were done as part of the aging management program that calls for an in-depth inspection of the reactor vessel. Inspections of more than 2,000 bolts in the reactor’s removable insert liner identified issues with roughly 11% of the bolts that required further analysis. Entergy replaced bolts as appropriate, and the unit returned to service on June 16, 2016. The repair costs were accounted for as deferred refueling outage costs and will be amortized over the plant’s subsequent fuel cycle. In addition to the repair costs, Entergy lost net revenue due to the plant being offline. Entergy estimates the negative effect on earnings was approximately $51 million pre-tax in second quarter 2016. Entergy evaluated the scope and duration of Indian Point 3’s scheduled refueling outage planned for 2017. Based on the results of that evaluation and analysis, Entergy is extending Indian Point 3’s 2017 outage by 20 days.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Grand Gulf
Grand Gulf began a maintenance outage on September 8, 2016 to replace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant in an outage for additional training and other steps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.
Based on the plant’s recent performance indicators, in November 2016 the NRC placed Grand Gulf in the “regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. Additionally, in October 2016 the NRC commenced a special inspection to investigate the circumstances surrounding the unplanned unavailability of an alternate heat removal system during the September 2016 replacement of the heat removal pump and to evaluate the licensee’s actions to address the causes of the event. Depending upon the findings of the NRC and the plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of the NRC’s Reactor Oversight Action Matrix.
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 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
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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 operating segments. Regulations require Entergy subsidiaries to decommission the nuclear power plants after each facility is taken out of service, and cash is 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.
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 for those plants that do not have an announced shutdown date. For certain nuclear plants for whichThe estimate may include assumptions regarding the possibility that the plant may have an operating life shorter than the operating license has not been renewed yet, this estimate assumes a highexpiration, as well as assumptions regarding the probability that the plant’s license will be renewed.renewed for those plants that have not yet received operating license renewal. Second, an assumption must be made whether all decommissioning activity will proceed immediately upon plant retirement, or whether the plant will be placed in SAFSTOR status. 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. A change of assumption regarding either the probability of license renewal, the period of continued operation, or the use of a SAFSTOR period can change the present value of the asset retirement obligations.
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% to 3% annually. A 50-basis point change in this assumption could change the estimated present value of the decommissioning liabilities by approximately 8%5% to 15%. The timing assumption influences the significance of the effect of a change in the estimated inflation or cost escalation rate because the effect increases with the length of time assumed before decommissioning activity ends.
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. The current Presidential administration, however, has defunded the Yucca Mountain project. The DOE
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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’s nuclear plant owners are continuing to pursue damage 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 include cost estimates for spent fuel storage. These estimates could change in the future, however, based on the expected timing of when the DOE begins to fulfill its obligation to receive and store spent nuclear fuel.
See Note 8 to the financial statements for further discussion of Entergy’s spent nuclear fuel litigation.Technology and Regulation - Over the past several years, more practical experience with the actual decommissioning of nuclear facilities has been gained and that experience has been incorporated into Entergy’s current decommissioning cost estimates. Given the long duration of decommissioning projects, additional experience, including technological advancements in decommissioning, could occur, however, and affect current cost estimates. In addition, if regulations regarding nuclear decommissioning were to change, this could significantly affect cost estimates.
Interest Rates - The estimated decommissioning costs that are the basis for the recorded decommissioning liability are discounted to present value using a credit-adjusted risk-free rate. When the decommissioning liability is revised, increases in cash flows are discounted using the current credit-adjusted risk-free rate. Decreases in estimated cash flows are discounted using the credit-adjusted risk-free rate used previously in estimating the decommissioning liability that is being revised. Therefore, to the extent that a revised cost study results in an increase in estimated cash flows, a change in interest rates from the time of the previous cost estimate will affect the calculation of the present value of the revised decommissioning liability.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Revisions of estimated decommissioning costs that decrease the liability also result in a decrease in the asset retirement cost asset. For the non-rate-regulated portions of Entergy’s business, these reductions will immediately reduce operating expenses in the period of the revision if the reduction of the liability exceeds the amount of the undepreciated asset retirement cost asset at the date of the revision. Revisions of estimated decommissioning costs that increase the liability result in an increase in the asset retirement cost asset, which is then depreciated over the asset’s remaining economic life. For a plant in the non-rate-regulated portions of Entergy’s business for which the plant’s value is impaired, however, including a plant that is shutdown, or is nearing its shutdown date, the increase in the liability is likely to immediately increase operating expense in the period of the revision and not increase the asset retirement cost asset. See Note 114 to the financial statements for further discussion of impairment of long-lived assets and Note 9 to the financial statements for further discussion of decommissioning cost revisions.asset retirement obligations.
Utility Regulatory Accounting
Entergy’s Utility operating companies and System Energy are subject to retail regulation by their respective state and local regulators and to wholesale regulation by the FERC. Because these regulatory agencies set the rates the Utility operating companies and System Energy are allowed to charge customers based on allowable costs, including a reasonable return on equity, the Utility operating companies and System Energy apply accounting standards that require the financial statements to reflect the effects of rate regulation, including the recording of regulatory assets and liabilities. Regulatory assets represent incurred costs that have been deferred because they are probable of future recovery from customers through regulated rates. Regulatory liabilities represent the excess recovery of costs that have been deferred because it is probable such amounts will be returned to customers through future regulated rates. See Note 2 to the financial statements for a discussion of rate and regulatory matters, including details of Entergy’s and the Registrant Subsidiaries’ regulatory assets and regulatory liabilities.
For each regulatory jurisdiction in which they conduct business, the Utility operating companies and System Energy assess whether the regulatory assets and regulatory liabilities continue to meet the criteria for probable future recovery or settlement at each balance sheet date and when regulatory events occur. This assessment includes consideration of recent rate orders, historical regulatory treatment for similar costs, and factors such as changes in
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
applicable regulatory and political environments. If the assessments made by the Utility operating companies and System Energy are ultimately different than actual regulatory outcomes, it could materially affect the results of operations, financial position, and cash flows of Entergy or the Registrant Subsidiaries.
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 both of its operating segments, and Entergy evaluates these assets against the market economics and under the accounting rules for impairment when there are indications that an impairment may exist. This evaluation involves a significant degree of estimation and uncertainty. In the Entergy Wholesale Commodities business, Entergy’s investments in merchant generation assets are subject to impairment if adverse market or regulatory conditions arise, particularly if it leads to a decision or an expectation that Entergy will operate a plant for a shorter period than previously expected; if there is a significant adverse change in the physical condition of a plant; if investment in a plant significantly exceeds previously-expected amounts; or, for Indian Point 2 and Indian Point 3, if their operating licenses are not renewed.
If an asset is considered held for use, and Entergy concludes that events and circumstances are present indicating that an impairment analysis should be doneperformed under the accounting standards, the sum of the expected undiscounted future cash flows from the asset are compared to the asset’s carrying value. The carrying value of the asset includes any capitalized asset retirement cost associated with the 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 the expected undiscounted future cash flows are less than the carrying value and the carrying value exceeds the fair value, Entergy is required to record an impairment charge to write the asset down to its fair value. If an asset is considered 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.
The expected future cash flows are based on a number of key assumptions, including:
Future power and fuel prices - Electricity and gas prices can be very volatile. This volatility 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, these transactions are relatively infrequent, the market for such assets is volatile, and the value of individual assets is affected by factors unique to those assets.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Future operating costs - Entergy assumes relatively minor annual increases in operating costs. Technological or regulatory changes that have a significant effect on operations could cause a significant change in these assumptions.
Timing and the life of the asset - Entergy assumes an expected life of the asset and currently assumes, for some of its nuclear units, that the plant’s license will be renewed beyond its current expiration date.asset. A change in the timing assumption, whether due to management decisions regarding operation of the plant, the regulatory process, or operational or other factors, could have a significant effect on the expected future cash flows and result in a significant effect on operations.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
See “Impairment of Long-Lived Assets” in Note 114 to the financial statements for a discussion of the impairments of the Vermont Yankee,Palisades, Indian Point 2 and 3, FitzPatrick, and Pilgrim and Palisades plants.
Entergy evaluates investment securities in the Entergy Wholesale Commodities’ nuclear decommissioning trust funds with 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. 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 2015, 2014, or 2013. 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. As discussed in Note 1 to the financial statements, unrealized losses on equity securities that are considered other-than-temporarily impaired are recorded in earnings for Entergy Wholesale Commodities. See Note 16 to the financial statements for details on the decommissioning trust funds.
Taxation and Uncertain Tax Positions
Management exercises significant judgment in evaluating the potential tax effects of Entergy’s operations, transactions, and other events. Entergy Wholesale Commodities did not record material chargesaccounts for uncertain income tax positions using a recognition model under a two-step approach with a more likely-than-not recognition threshold and a measurement approach based on the largest amount of tax benefit that is greater than 50% likely of being realized upon settlement. Management evaluates each tax position based on the technical merits and facts and circumstances of the position, assuming the position will be examined by a taxing authority having full knowledge of all relevant information. Significant judgment is required to other income in 2015, 2014, or 2013 resulting fromdetermine whether available information supports the assertion that the recognition threshold has been met. Additionally, measurement of other-than-temporary impairmentunrecognized tax benefits to be recorded in the consolidated financial statements is based on the probability of equity securities helddifferent potential outcomes. Income tax expense and tax positions recorded could be significantly affected by events such as additional transactions contemplated or consummated by Entergy as well as audits by taxing authorities of the tax positions taken in its decommissioning trust funds. transactions. Management believes that the financial statement tax balances are accounted for and adjusted appropriately each quarter as necessary in accordance with applicable authoritative guidance; however, the ultimate outcome of tax matters could result in favorable or unfavorable effects on the consolidated financial statements. Entergy’s income taxes, including unrecognized tax benefits, open audits, and other significant tax matters are discussed in Note 3 to the financial statements.
It is possible that significant changes will be made to the Internal Revenue Code in 2017. Both the U.S. House of Representatives and the Trump administration have advanced proposals. Based on current proposals, a reduction in the statutory rate would be offset by modification or elimination of certain tax deductions. Entergy is monitoring the legislative progress. It is possible that such legislative changes would have a significant effect on the financial position, results of operations, or cash flows of Entergy and the Registrant Subsidiaries.
Qualified Pension and Other Postretirement Benefits
Entergy sponsors qualified, defined benefit pension plans that cover substantially all employees, including cash balance plans for employees whose most recent date of hire or rehire is after June 30, 2014 (or for certain eligible bargaining employees, such later date provided in their applicable collective bargaining agreements) and final average pay plans for substantially all employees whose more recent date of hire or rehire is before July 1, 2014.plans. Additionally, Entergy currently provides other postretirement health care and life insurance benefits for substantially all full-time employees whose most recent date of hire or rehire is before July 1, 2014 (and for certain eligible bargaining employees, such later date provided in their applicable collective bargaining agreements), and who reach retirement age and meet certain eligibility requirements while still working for Entergy.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy’s reported costs of providing these benefits, as described in Note 11 to the financial statements, are affected 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;
Projectedqualified pension and other postretirement health care and life insurance costs include discount rates, projected healthcare cost trend rates;
Expectedrates, expected long-term rate of return on plan assets;
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Rateassets, rate of increase in future compensation levels;
Retirement rates;levels, retirement rates and
Mortality mortality rates.
Annually, Entergy reviews and, when necessary, adjusts the first four assumptions listed above on an annual basisfor the pension and adjusts them as necessary.other postretirement plans. Every three-to-five years, a formal actuarial assumption experience study that compares assumptions to the actual experience of the pension and other postretirement health care and life insurance plans is conducted. The falling interest rate environment over the past few years and volatility in the financial equity markets have affected 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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions resulted in an increase at December 31, 2014 of $504.4 million in the qualified pension benefit obligation and $94.4 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $77.4 million and other postretirement cost by approximately $12.3 million. Pension funding guidelines, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.Discount rates
In selecting an assumed discount rate to calculate benefit obligations, Entergy uses a yield curve based on high-quality corporate debt. Based on recent market trends,Before 2016 the discount rates used to calculate its 2015 qualified pensionestimate the service cost and interest cost components of benefit costs were the same as the weighted-average discount rate used to measure the benefit obligation ranged from 4.51% to 4.79% for its specific pension plans (4.67% combined rate for all pension plans).at the beginning of the year. In 2016, Entergy refined its approach to estimating the service cost and interest cost componentscomponents. Under the refined approach, instead of using the weighted-average benefit obligation discount rate at the beginning of the year, the 2016 service and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement had the effect of lowering 2016 qualified pension costs by $61 million and 2016 other postretirement health care and life insurance costs, which had the effect of lowering qualified pensionbenefit costs by $61.4$15 million. This refined approach discounts the individual expected cash flows underlying the service cost and interest cost using the applicable spot rates derived from the yield curve used to discount the cash flows used to measure the pension obligation. Historically, Entergy estimated these service and interest cost components utilizing a single weighted-average discount rate derived from the yield curve used to measure the benefit obligation at the beginning of the period. This is a change in accounting estimate and accordingly the effect will be reflected prospectively. The benefit obligations measured under this approach are unchanged. The spot rates used to determine the qualified pension service cost ranged from 4.52 % to 5.08 % (5.00% combined rate for all pension plans) and the interest cost ranged from 3.68 % to 4.14% (3.90% combined for all pension plans), respectively. Under the prior approach, the rate for qualified pension service and interest costs would have been a weighted average rate of approximately 4.67%.
The discount rates used to calculate its 2014 qualified pension benefit obligation and 2015 qualified pension cost ranged from 4.03% to 4.40% for its specific pension plans (4.27% combined rate for all pension plans). The discount rates used to calculate its 2013 qualified pension benefit obligation and 2014 qualified pension cost ranged from 5.04% to 5.26% for its specific pension plans (5.14% combined rate for all pension plans). 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 rate used to calculate the 2015 postretirementProjected health care and life insurance benefit obligation was 4.60%. The 2016 postretirementcost trend rates
Entergy’s health care cost trend is affected by both medical cost inflation, and life insurance benefit service and interest cost,with respect to capped costs under the more refined discount rate calculation, was reduced by $14.6 million. The effective spot rates used to determineplan, the postretirement health care and life insurance benefit service cost and interest costs were 4.92% and 3.78%, respectively. Under the prior approach, the rate would have been a weighted-average rate for other postretirement service and interest costseffects of approximately 4.60%.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
The discount rate used to calculate its 2014 postretirement health care and life insurance benefit obligation and 2015 postretirement health care and life insurance benefit cost was 4.23%. The discount rate used to calculate its 2013 postretirement health care and life insurance benefit obligation and 2014 postretirement health care and life insurance benefit cost was 5.05%. The discount rate used to calculate its 2012 postretirement health care and life insurance benefit obligation and 2013 postretirement health care and life insurance benefit cost was 4.36%.
general inflation. Entergy reviews actual recent cost trends and projected future trends in establishing its health care cost trend rates. Based on this review, Entergy’s health care cost trend rate assumption used in measuring the December 31, 2015 accumulated postretirement benefit obligation and 2016 postretirement cost was 6.75% for pre-65 retirees and 7.55% for post-65 retirees for 2015, gradually decreasing each successive year until it reaches 4.75% in 2024 and beyond for both pre-65 and post-65 retirees. Entergy’s health care cost trend rate assumption used in measuring the December 31, 2014 accumulated postretirement benefit obligation and 2015 postretirement cost was 7.10% for pre-65 retirees and 7.70% for post-65 retirees for 2014, gradually decreasing each successive year until it reaches 4.75% in 2023 and beyond for both pre-65 and post-65 retirees. Entergy’s assumed health care cost trend rate assumption used in measuring the December 31, 2013 accumulated postretirement benefit obligation and 2014 postretirement cost was 7.25% for pre-65 retirees and 7.00% 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 assumed health care cost trend rate assumption used in measuring 2013 postretirement cost was 7.50% for pre-65 retirees and 7.25% for post-65 retirees, gradually decreasing each successive year until it reaches 4.75% in 2022 and beyond for both pre-65 and post-65 retirees.
The assumedExpected long-term rate of increase in future compensation levels used to calculate 2015 and 2014 benefit obligations was 4.23%.return on plan assets
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 conducts periodic asset/liability studies in order to set its target asset allocations.
Since 2003, Entergy has targeted an asset allocation for its qualified pension plan assets of roughly 65% equity securities and 35% fixed-income securities. In 2011, Entergy completed and adopted an optimization study in 2011a liability driven investment strategy for theits pension assets, thatwhich recommended that the target asset allocation adjust dynamically over time, based on the funded status of the plan, from its current allocation to an ultimate allocation of 45% equity and 55% fixed income securities. The ultimate asset allocation is expected to be attained when the plan is 105% funded.
The current target allocations for both Entergy’s non-taxable other postretirement benefit assets and its taxable other postretirement benefit assets are 65% equity securities and 35% fixed-income securities. This takes into accountDuring the first quarter 2017, Entergy will be implementing a new asset allocation adjustments that were made during 2012.strategy, which will result in an overall shift to more fixed income in the non-taxable trusts and no material changes in asset allocation to the taxable trust.
Entergy’s expected long term rate of return on qualified pension assets used to calculate 2015, 2014, and 2013 qualified pension costs was 8.25%, 8.5%, and 8.5%, respectively and will be 7.75% for 2016. Entergy’s expected long term rate of return on tax deferred other postretirement assets used to calculate other postretirement costs was 8.05%, 8.3%, and 8.5% in 2015, 2014, and 2013, respectively. It will be 7.75% for 2016. For Entergy’s taxable postretirement assets, the expected long term rate of return was 6.25% in 2015 and 6.5% in 2014 and 2013. It will be 6.00% in 2016.
Accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods and deferral of gains and losses arising from the difference between actuarial estimates and actual experience. Prior service costs/credits and deferred gains and losses are then amortized into expense over future periods. Certain decisions, including workforce reductions and plan amendments, may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment losses or gains. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
Retirement and mortality rates
In December 2016 the Internal Revenue Service issued proposed mortality regulations for single employer plans for determining cash contribution requirements, as established by the Employee Retirement Income Security Act of 1974, as amended and the Internal Revenue Code of 1986, as amended. The proposed regulations would be effective for plan years beginning on or after January 1, 2018, and, as such, have no impact on 2017 plan year minimum required contributions. The proposed regulations are generally anticipated to increase the 2018 minimum funding target liability for most pension plans by about 4% to 8%. The new mortality tables were adopted for accounting in 2014.
Cost SensitivityCosts and Sensitivities
The estimated 2017 and actual 2016 qualified pension and other postretirement costs and related underlying assumptions and sensitivities are shown below:
|
| | | | |
| Costs | | Estimated 2017 | | 2016 |
| | | (In Millions) |
| Qualified pension cost | | $214 | | $215 |
| Other postretirement cost | | $26 | | $20 |
| | | | | |
| Assumptions | | 2017 | | 2016 |
| Discount rates | | | | |
| Qualified pension | | | | |
| Service cost | | 4.75% | | 5.00% |
| Interest cost | | 3.73% | | 3.90% |
| Other postretirement | | | | |
| Service cost | | 4.60% | | 4.92% |
| Interest cost | | 3.61% | | 3.78% |
| | | | | |
| Expected long-term rates of return | | | | |
| Qualified pension assets | | 7.50% | | 7.75% |
| Other postretirement - non-taxable assets | | 6.50% - 6.90% | | 7.75% |
| Other postretirement - taxable assets | | 5.75% | | 6.00% |
| | | | | |
| Weighted-average rate of future compensation | | 3.98% | | 4.23% |
| | | | | |
| Assumed health care cost trend rates | | | | |
| Pre-65 retirees | | 6.55% | | 6.75% |
| Post-65 retirees | | 7.25% | | 7.55% |
| Ultimate rate | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond | | 2026 | | 2024 |
Actual asset returns have an effect on Entergy’s qualified pension and other postretirement costs. In 2016, Entergy’s actual average annual return on qualified pension assets was approximately 8.80% and for other postretirement assets was approximately 7.20%, as compared with the 2016 expected long-term rates of return discussed above. For 2017, Entergy decreased its expected long-term rate of return assumptions, to take into account changes in capital market assumptions and results of asset allocation studies.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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).millions):
| | | Actuarial Assumption | | Change in Assumption | | Impact on 2015 Qualified Pension Cost | | Impact on 2015 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Qualified Projected Benefit Obligation |
| | | Increase/(Decrease) | | Increase/(Decrease) |
| Discount rate | | (0.25%) | |
| $25,309 |
| |
| $228,185 |
| | (0.25%) | |
| $24 |
| |
| $235 |
|
| Rate of return on plan assets | | (0.25%) | |
| $11,178 |
| |
| $— |
| | (0.25%) | |
| $14 |
| | $- |
|
| Rate of increase in compensation | | 0.25% | |
| $8,973 |
| |
| $35,458 |
| | 0.25% | |
| $6 |
| |
| $33 |
|
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation to changes in certain actuarial assumptions (dollars in thousands).millions):
| | | Actuarial Assumption | | Change in Assumption | | Impact on 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | Increase/(Decrease) | | Increase/(Decrease) |
| Discount rate | | (0.25%) | | $4,578 | | $50,925 | | (0.25%) | |
| $4 |
| |
| $50 |
|
| Health care cost trend | | 0.25% | | $7,450 | | $42,890 | | 0.25% | |
| $6 |
| |
| $41 |
|
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. See 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. Additionally, accounting standards allow for the deferral of prior service costs/credits arising from plan amendments that attribute an increase or decrease in benefits to employee service in prior periods. Prior service costs/credits are then amortized into expense over the average future working life of active employees. Certain decisions, including workforce reductions, plan amendments, and plant shutdowns may significantly reduce the expense amortization period and result in immediate recognition of certain previously-deferred costs and gains/losses in the form of curtailment gains or losses. Similarly, payments made to settle benefit obligations can also result in recognition in the form of settlement losses or gains.
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 Accounting standards require an employer to recognize in its balance sheet the funded status of its benefit plans. See Note 11 to the financial statements for a further discussion of Entergy’s funded status.
Funding
In 2015, Entergy’s total qualified pension cost was $321.1 million, including a $0.4 million curtailment charge related to announced plant closures. Entergy anticipates 2016 qualified pension cost to be $211.8 million. Entergy’s pension funding in 2016 was approximately $395.8 million for 2015. Entergy’s 2016-2018$390 million. Entergy estimates pension contributions to the pension trust are currently estimated towill be approximately $1.1 billion, including $387.5$409 million in 2016;2017; although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
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 that, 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 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.
Moving Ahead for Progress in the 21st Century Act (MAP-21) became federal law in July 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. TheThese 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 historically low interest rates that existed when the law was enacted. The law did not reduce contribution requirements over the long term.
The interest rate stabilization periods of MAP-21 were extended by the Highway and Transportation Funding Act (HATFA) became federal law in August 2014. HATFA’s pension provisions provided a five-year extension of2014 and the MAP-21 pension funding stabilization.Bipartisan Budget Act in 2015.
Total postretirement health care and life insurance benefit costs for Entergy in 2015 were $66.2 million. Entergy expects 2016 postretirement health care and life insurance benefit costs to be $19.5 million. Entergy contributed $62.7 million to its postretirement plans in 2015. Entergy’s current estimate of 2016-2018 contributions to its other postretirement plans is approximately $148.6 million, including $52.8 million in 2016.
Federal Healthcare Legislation
TheIn 2010 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, as amended, certain provisions of the PPACA. Entergy has implemented the major provisions of the law.
Aimposed a 40% excise tax on per capita medical benefit costs that exceed certain thresholdsthresholds. The excise tax is due to take effect beginning in 2018. There are still many technical issues, however, that have not been finalized. In 2017, under the new Presidential administration, the PPACA is expected to be further amended or repealed and replaced. Entergy will continue to monitor these developments to determine the possible effect on Entergy.
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 liabilities 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
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
amounts of environmental liabilities 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.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
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 possible, or remote and records liabilities for cases that have a probable likelihood of loss and the loss 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, financial position, and cash flows of Entergy or the 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. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. In August 2015 theWith FASB issuedissuance of ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date.Date,” The ASU defers the effective date of ASU 2014-09 for all entities by one year. ASU 2014-09 is effective for Entergy for the first quarter 2018. Entergy does not expectis evaluating its transition approach (which will either be a full retrospective or a modified retrospective transition method) and the effects of the new guidance, most significantly on its accounting for contributions in aid of construction. Entergy’s evaluation of ASU 2014-09 tohas not identified any effects that it expects will affect materially its results of operations, financial position, or cash flows. Entergy will continue to monitor, however, the development of industry specific application guidance that could have an effect on this assessment.
In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In February 2015 the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to Consolidation Analysis” which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The ASU affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. ASU 2015-02 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2015-02 to affect materially its results of operations, financial position, or cash flows.
In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The ASU requires investments in equity investments,securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of investments in equity investments withoutsecurities that do not have a readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on investments in equity investmentssecurities held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy is evaluating the ASU for other effects on the results of operations, financial position, and cash flows.
In February 2016 the FASB issued ASU No. 2016-02, “Leases (Topic 842).” The ASU’s core principle is that “a lessee should recognize the assets and liabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. ASU 2016-02 is effective for Entergy for the first quarter 2019, with early adoption permitted. Entergy expects that ASU 2016-02 will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases. Entergy is evaluating ASU 2016-02 for other effects on its results of operations, financial position, and cash flows, as well as the potential to early adopt the ASU.
In March 2016 the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The ASU seeks to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The statement is effective beginning in 2017 and Entergy will prospectively recognize all income tax effects related to share-based payments through the income statement. Entergy expects to record approximately $12 million in income tax expense in the first quarter of 2017 related to implementing ASU 2016-09.
Entergy Corporation and Subsidiaries
Management’s Financial Discussion and Analysis
In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial instruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized immediately in earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.
In October 2016 the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Assets Other Than Inventory.” The ASU requires entities to recognize the income tax consequences of intra-entity asset transfers, other than inventory, at the time the transfer occurs. ASU 2016-16 is effective for Entergy for the first quarter 2018 and will affect its statement of financial position by requiring recognition of deferred tax assets or liabilities arising from intra-entity asset transfers. Entergy is evaluating ASU 2016-16 for other effects on its results of operations, financial position, and 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. The 2013 COSO Framework was utilized for management’s assessment. 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’s independent registered public accounting firm, Deloitte & Touche LLP, has issued an attestation report on the effectiveness of Entergy Corporation’s internal control over financial reporting as of December 31, 2015.2016.
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 2013 COSO criteria, management believes that Entergy and each of the Registrant Subsidiaries maintained effective internal control over financial reporting as of December 31, 2015.2016. 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, Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc. |
HUGH T. MCDONALDRICHARD C. RILEY
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 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. | THEODORE H. BUNTING, JR. Chairman of the Board, President, and Chief Executive Officer of System Energy Resources, Inc. |
| | ENTERGY CORPORATION AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 | 2016 |
| 2015 |
| 2014 |
| 2013 |
| 2012 |
| | (In Thousands, Except Percentages and Per Share Amounts) | (In Thousands, Except Percentages and Per Share Amounts) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $11,513,251 |
|
|
| $12,494,921 |
| |
| $11,390,947 |
| |
| $10,302,079 |
|
|
| $11,229,073 |
|
| $10,845,645 |
|
|
| $11,513,251 |
| |
| $12,494,921 |
| |
| $11,390,947 |
|
|
| $10,302,079 |
|
| Net income (loss) |
| ($156,734 | ) |
|
| $960,257 |
| |
| $730,572 |
| |
| $868,363 |
|
|
| $1,367,372 |
|
| ($564,503 | ) |
|
| ($156,734 | ) | |
| $960,257 |
| |
| $730,572 |
|
|
| $868,363 |
|
| Earnings (loss) per share: | |
| | | | | |
|
| |
| |
| | | | | |
|
| |
|
| Basic |
| ($0.99 | ) |
|
| $5.24 |
| |
| $3.99 |
| |
| $4.77 |
|
|
| $7.59 |
|
| ($3.26 | ) |
|
| ($0.99 | ) | |
| $5.24 |
| |
| $3.99 |
|
|
| $4.77 |
|
| Diluted |
| ($0.99 | ) |
|
| $5.22 |
| |
| $3.99 |
| |
| $4.76 |
|
|
| $7.55 |
|
| ($3.26 | ) |
|
| ($0.99 | ) | |
| $5.22 |
| |
| $3.99 |
|
|
| $4.76 |
|
| Dividends declared per share |
| $3.34 |
|
|
| $3.32 |
| |
| $3.32 |
| |
| $3.32 |
|
|
| $3.32 |
|
| $3.42 |
|
|
| $3.34 |
| |
| $3.32 |
| |
| $3.32 |
|
|
| $3.32 |
|
| Return on common equity | (1.83 | %) |
| 9.58 | % | | 7.56 | % | | 9.33 | % |
| 15.43 | % | (6.73 | %) |
| (1.83 | %) | | 9.58 | % | | 7.56 | % |
| 9.33 | % |
| Book value per share, year-end |
| $51.89 |
|
|
| $55.83 |
| |
| $54.00 |
| |
| $51.72 |
|
|
| $50.81 |
|
| $45.12 |
|
|
| $51.89 |
| |
| $55.83 |
| |
| $54.00 |
|
|
| $51.72 |
|
| Total assets |
| $44,647,681 |
|
|
| $46,414,455 |
| |
| $43,290,290 |
| |
| $43,087,339 |
|
|
| $40,597,676 |
|
| $45,904,434 |
|
|
| $44,647,681 |
| |
| $46,414,455 |
| |
| $43,290,290 |
|
|
| $43,087,339 |
|
| Long-term obligations (a) |
| $13,456,742 |
|
|
| $12,627,180 |
| |
| $12,265,971 |
| |
| $12,026,207 |
|
|
| $10,164,622 |
|
| $14,695,422 |
|
|
| $13,456,742 |
| |
| $12,627,180 |
| |
| $12,265,971 |
|
|
| $12,026,207 |
|
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and subsidiary preferred stock without sinking fund that is not presented as equity on the balance sheet. |
| | | 2015 |
| 2014 |
| 2013 |
| 2012 |
| 2011 | 2016 |
| 2015 |
| 2014 |
| 2013 |
| 2012 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Utility electric operating revenues: | |
|
| |
|
| |
|
| |
|
| |
| |
|
| |
|
| |
|
| |
|
| |
|
| Residential |
| $3,518 |
|
|
| $3,555 |
|
|
| $3,396 |
|
|
| $3,022 |
|
|
| $3,369 |
|
| $3,288 |
|
|
| $3,518 |
|
|
| $3,555 |
|
|
| $3,396 |
|
|
| $3,022 |
|
| Commercial | 2,516 |
|
| 2,553 |
|
| 2,415 |
|
| 2,174 |
|
| 2,333 |
| 2,362 |
|
| 2,516 |
|
| 2,553 |
|
| 2,415 |
|
| 2,174 |
|
| Industrial | 2,462 |
|
| 2,623 |
|
| 2,405 |
|
| 2,034 |
|
| 2,307 |
| 2,327 |
|
| 2,462 |
|
| 2,623 |
|
| 2,405 |
|
| 2,034 |
|
| Governmental | 223 |
|
| 227 |
|
| 218 |
|
| 198 |
|
| 205 |
| 217 |
|
| 223 |
|
| 227 |
|
| 218 |
|
| 198 |
|
| Total retail | 8,719 |
|
| 8,958 |
|
| 8,434 |
|
| 7,428 |
|
| 8,214 |
| 8,194 |
|
| 8,719 |
|
| 8,958 |
|
| 8,434 |
|
| 7,428 |
|
| Sales for resale | 249 |
|
| 330 |
|
| 210 |
|
| 179 |
|
| 216 |
| 236 |
|
| 249 |
|
| 330 |
|
| 210 |
|
| 179 |
|
| Other | 341 |
|
| 304 |
|
| 298 |
|
| 264 |
|
| 244 |
| 437 |
|
| 341 |
|
| 304 |
|
| 298 |
|
| 264 |
|
| Total |
| $9,309 |
|
|
| $9,592 |
|
|
| $8,942 |
|
|
| $7,871 |
|
|
| $8,674 |
|
| $8,867 |
|
|
| $9,309 |
|
|
| $9,592 |
|
|
| $8,942 |
|
|
| $7,871 |
|
| | | | | | | | | | | | | | | | | | | |
| Utility billed electric energy sales (GWh): |
|
|
|
|
| |
|
| |
|
| |
|
|
|
|
|
| |
|
| |
|
| |
|
| Residential | 36,068 |
|
| 35,932 |
|
| 35,169 |
|
| 34,664 |
|
| 36,684 |
| 35,112 |
|
| 36,068 |
|
| 35,932 |
|
| 35,169 |
|
| 34,664 |
|
| Commercial | 29,348 |
|
| 28,827 |
|
| 28,547 |
|
| 28,724 |
|
| 28,720 |
| 29,197 |
|
| 29,348 |
|
| 28,827 |
|
| 28,547 |
|
| 28,724 |
|
| Industrial | 44,382 |
|
| 43,723 |
|
| 41,653 |
|
| 41,181 |
|
| 40,810 |
| 45,739 |
|
| 44,382 |
|
| 43,723 |
|
| 41,653 |
|
| 41,181 |
|
| Governmental | 2,514 |
|
| 2,428 |
|
| 2,412 |
|
| 2,435 |
|
| 2,474 |
| 2,547 |
|
| 2,514 |
|
| 2,428 |
|
| 2,412 |
|
| 2,435 |
|
| Total retail | 112,312 |
|
| 110,910 |
|
| 107,781 |
|
| 107,004 |
|
| 108,688 |
| 112,595 |
|
| 112,312 |
|
| 110,910 |
|
| 107,781 |
|
| 107,004 |
|
| Sales for resale | 9,274 |
|
| 9,462 |
|
| 3,020 |
|
| 3,200 |
|
| 4,111 |
| 11,054 |
|
| 9,274 |
|
| 9,462 |
|
| 3,020 |
|
| 3,200 |
|
| Total | 121,586 |
|
| 120,372 |
|
| 110,801 |
|
| 110,204 |
|
| 112,799 |
| 123,649 |
|
| 121,586 |
|
| 120,372 |
|
| 110,801 |
|
| 110,204 |
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Wholesale Commodities: | |
|
| |
|
| |
|
| |
|
| |
| |
|
| |
|
| |
|
| |
|
| |
|
| Operating revenues |
| $2,062 |
| |
| $2,719 |
| |
| $2,313 |
| |
| $2,326 |
| |
| $2,414 |
|
| $1,850 |
| |
| $2,062 |
| |
| $2,719 |
| |
| $2,313 |
| |
| $2,326 |
|
| Billed electric energy sales (GWh) | 39,745 |
| | 44,424 |
| | 45,127 |
| | 46,178 |
| | 43,497 |
| 35,881 |
| | 39,745 |
| | 44,424 |
| | 45,127 |
| | 46,178 |
|
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 accompanying consolidated balance sheets of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20152016 and 2014,2015, and the related consolidated statements of operations, comprehensive income (loss), cash flows, and changes in equity for each of the three years in the period ended December 31, 2015.2016. 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, 20152016 and 2014,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, 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, 2015,2016, based on the criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 25, 201624, 2017 expressed an unqualified opinion on the Corporation’s internal control over financial reporting.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF OPERATIONS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands, Except Share Data) | | (In Thousands, Except Share Data) |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $9,308,678 |
| |
| $9,591,902 |
| |
| $8,942,360 |
| |
| $8,866,659 |
| |
| $9,308,678 |
| |
| $9,591,902 |
|
| Natural gas | | 142,746 |
| | 181,794 |
| | 154,353 |
| | 129,348 |
| | 142,746 |
| | 181,794 |
|
| Competitive businesses | | 2,061,827 |
| | 2,721,225 |
| | 2,294,234 |
| | 1,849,638 |
| | 2,061,827 |
| | 2,721,225 |
|
| TOTAL | | 11,513,251 |
| | 12,494,921 |
| | 11,390,947 |
| | 10,845,645 |
| | 11,513,251 |
| | 12,494,921 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 2,452,171 |
| | 2,632,558 |
| | 2,445,818 |
| | 1,809,200 |
| | 2,452,171 |
| | 2,632,558 |
|
| Purchased power | | 1,390,805 |
| | 1,915,414 |
| | 1,554,332 |
| | 1,220,527 |
| | 1,390,805 |
| | 1,915,414 |
|
| Nuclear refueling outage expenses | | 251,316 |
| | 267,679 |
| | 256,801 |
| | 208,678 |
| | 251,316 |
| | 267,679 |
|
| Other operation and maintenance | | 3,354,981 |
| | 3,310,536 |
| | 3,331,934 |
| | 3,296,711 |
| | 3,354,981 |
| | 3,310,536 |
|
| Asset write-offs, impairments, and related charges | | 2,104,906 |
| | 179,752 |
| | 341,537 |
| | 2,835,637 |
| | 2,104,906 |
| | 179,752 |
|
| Decommissioning | | 280,272 |
| | 272,621 |
| | 242,104 |
| | 327,425 |
| | 280,272 |
| | 272,621 |
|
| Taxes other than income taxes | | 619,422 |
| | 604,606 |
| | 600,350 |
| | 592,502 |
| | 619,422 |
| | 604,606 |
|
| Depreciation and amortization | | 1,337,276 |
| | 1,318,638 |
| | 1,261,044 |
| | 1,347,187 |
| | 1,337,276 |
| | 1,318,638 |
|
| Other regulatory charges (credits) - net | | 175,304 |
| | (13,772 | ) | | 45,597 |
| | 94,243 |
| | 175,304 |
| | (13,772 | ) |
| TOTAL | | 11,966,453 |
| | 10,488,032 |
| | 10,079,517 |
| | 11,732,110 |
| | 11,966,453 |
| | 10,488,032 |
|
| | | | | | | | | | | | | |
| Gain on sale of asset / business | | 154,037 |
| | — |
| | 43,569 |
| |
| Gain on sale of asset | | | — |
| | 154,037 |
| | — |
|
| | | | | | | | | | | | | |
| OPERATING INCOME (LOSS) | | (299,165 | ) | | 2,006,889 |
| | 1,354,999 |
| | (886,465 | ) | | (299,165 | ) | | 2,006,889 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 51,908 |
| | 64,802 |
| | 66,053 |
| | 67,563 |
| | 51,908 |
| | 64,802 |
|
| Interest and investment income | | 187,062 |
| | 147,686 |
| | 199,300 |
| | 145,127 |
| | 187,062 |
| | 147,686 |
|
| Miscellaneous - net | | (95,997 | ) | | (42,016 | ) | | (59,762 | ) | | (41,617 | ) | | (95,997 | ) | | (42,016 | ) |
| TOTAL | | 142,973 |
| | 170,472 |
| | 205,591 |
| | 171,073 |
| | 142,973 |
| | 170,472 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 670,096 |
| | 661,083 |
| | 629,537 |
| | 700,545 |
| | 670,096 |
| | 661,083 |
|
| Allowance for borrowed funds used during construction | | (26,627 | ) | | (33,576 | ) | | (25,500 | ) | | (34,175 | ) | | (26,627 | ) | | (33,576 | ) |
| TOTAL | | 643,469 |
| | 627,507 |
| | 604,037 |
| | 666,370 |
| | 643,469 |
| | 627,507 |
|
| | | | | | | | | | | | | |
| INCOME (LOSS) BEFORE INCOME TAXES | | (799,661 | ) | | 1,549,854 |
| | 956,553 |
| | (1,381,762 | ) | | (799,661 | ) | | 1,549,854 |
|
| | | | | | | | | | | | | |
| Income taxes | | (642,927 | ) | | 589,597 |
| | 225,981 |
| | (817,259 | ) | | (642,927 | ) | | 589,597 |
|
| | | | | | | | | | | | | |
| CONSOLIDATED NET INCOME (LOSS) | | (156,734 | ) | | 960,257 |
| | 730,572 |
| | (564,503 | ) | | (156,734 | ) | | 960,257 |
|
| | | | | | | | | | | | | |
| Preferred dividend requirements of subsidiaries | | 19,828 |
| | 19,536 |
| | 18,670 |
| | 19,115 |
| | 19,828 |
| | 19,536 |
|
| | | | | | | | | | | | | |
| NET INCOME (LOSS) ATTRIBUTABLE TO ENTERGY CORPORATION | |
| ($176,562 | ) | |
| $940,721 |
| |
| $711,902 |
| |
| ($583,618 | ) | |
| ($176,562 | ) | |
| $940,721 |
|
| | | | | | | | | | | | | |
| Earnings (loss) per average common share: | | |
| | |
| | |
| | |
| | |
| | |
|
| Basic | |
| ($0.99 | ) | |
| $5.24 |
| |
| $3.99 |
| |
| ($3.26 | ) | |
| ($0.99 | ) | |
| $5.24 |
|
| Diluted | |
| ($0.99 | ) | |
| $5.22 |
| |
| $3.99 |
| |
| ($3.26 | ) | |
| ($0.99 | ) | |
| $5.22 |
|
| | | | | | | | | | | | | |
| Basic average number of common shares outstanding | | 179,176,356 |
| | 179,506,151 |
| | 178,211,192 |
| | 178,885,660 |
| | 179,176,356 |
| | 179,506,151 |
|
| Diluted average number of common shares outstanding | | 179,176,356 |
| | 180,296,885 |
| | 178,570,400 |
| | 178,885,660 |
| | 179,176,356 |
| | 180,296,885 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
(Page left blank intentionally)
54
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (LOSS) | | | | |
| | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | |
| Net Income (Loss) |
| ($156,734 | ) | |
| $960,257 |
| |
| $730,572 |
|
| ($564,503 | ) | |
| ($156,734 | ) | |
| $960,257 |
|
| | | | | | | | | | | |
| Other comprehensive income (loss) | |
| | |
| | |
| |
| | |
| | |
|
| Cash flow hedges net unrealized gain (loss) | |
| | |
| | |
| |
| | |
| | |
|
| (net of tax expense (benefit) of $3,752, $96,141, and ($87,940)) | 7,852 |
| | 179,895 |
| | (161,682 | ) | |
| (net of tax expense (benefit) of ($55,298), $3,752, and $96,141) | | (101,977 | ) | | 7,852 |
| | 179,895 |
|
| Pension and other postretirement liabilities | |
| | |
| | |
| |
| | |
| | |
|
| (net of tax expense (benefit) of $61,576, ($152,763), and $220,899) | 103,185 |
| | (281,566 | ) | | 302,489 |
| |
| (net of tax expense (benefit) of ($3,952), $61,576, and ($152,763)) | | (2,842 | ) | | 103,185 |
| | (281,566 | ) |
| Net unrealized investment gains (losses) | |
| | |
| | |
| |
| | |
| | |
|
| (net of tax expense (benefit) of ($45,904), $66,594, and $118,878) | (59,138 | ) | | 89,439 |
| | 122,709 |
| |
| (net of tax expense (benefit) of $57,277, ($45,904), and $66,594) | | 62,177 |
| | (59,138 | ) | | 89,439 |
|
| Foreign currency translation | |
| | |
| | |
| |
| | |
| | |
|
| (net of tax expense (benefit) of ($345), ($404), and $131) | (641 | ) | | (751 | ) | | 243 |
| |
| (net of tax benefit of $689, $345, and $404) | | (1,280 | ) | | (641 | ) | | (751 | ) |
| Other comprehensive income (loss) | 51,258 |
| | (12,983 | ) | | 263,759 |
| (43,922 | ) | | 51,258 |
| | (12,983 | ) |
| | | | | | | | | | | |
| Comprehensive Income (Loss) | (105,476 | ) | | 947,274 |
| | 994,331 |
| (608,425 | ) | | (105,476 | ) | | 947,274 |
|
| Preferred dividend requirements of subsidiaries | 19,828 |
| | 19,536 |
| | 18,670 |
| 19,115 |
| | 19,828 |
| | 19,536 |
|
| Comprehensive Income (Loss) Attributable to Entergy Corporation |
| ($125,304 | ) | |
| $927,738 |
| |
| $975,661 |
|
| ($627,540 | ) | |
| ($125,304 | ) | |
| $927,738 |
|
| | | | | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Consolidated net income (loss) | |
| ($156,734 | ) | |
| $960,257 |
| |
| $730,572 |
| |
| ($564,503 | ) | |
| ($156,734 | ) | |
| $960,257 |
|
| Adjustments to reconcile consolidated net income (loss) to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 2,117,236 |
| | 2,127,892 |
| | 2,012,076 |
| | 2,123,291 |
| | 2,117,236 |
| | 2,127,892 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (820,350 | ) | | 596,935 |
| | 311,789 |
| | (836,257 | ) | | (820,350 | ) | | 596,935 |
|
| Asset write-offs, impairments, and related charges | | 2,104,906 |
| | 123,527 |
| | 341,537 |
| | 2,835,637 |
| | 2,104,906 |
| | 123,527 |
|
| Gain on sale of asset / business | | (154,037 | ) | | — |
| | (43,569 | ) | |
| Gain on sale of asset | | | — |
| | (154,037 | ) | | — |
|
| Changes in working capital: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 38,152 |
| | 98,493 |
| | (180,648 | ) | | (96,975 | ) | | 38,152 |
| | 98,493 |
|
| Fuel inventory | | (12,376 | ) | | 3,524 |
| | 4,873 |
| | 38,210 |
| | (12,376 | ) | | 3,524 |
|
| Accounts payable | | (135,211 | ) | | (12,996 | ) | | 94,436 |
| | 174,421 |
| | (135,211 | ) | | (12,996 | ) |
| Prepaid taxes and taxes accrued | | 81,969 |
| | (62,985 | ) | | (142,626 | ) | | (28,963 | ) | | 81,969 |
| | (62,985 | ) |
| Interest accrued | | (11,445 | ) | | 25,013 |
| | (3,667 | ) | | (7,335 | ) | | (11,445 | ) | | 25,013 |
|
| Deferred fuel costs | | 298,725 |
| | (70,691 | ) | | (4,824 | ) | | (241,896 | ) | | 298,725 |
| | (70,691 | ) |
| Other working capital accounts | | (113,701 | ) | | 112,390 |
| | (66,330 | ) | | 31,197 |
| | (113,701 | ) | | 112,390 |
|
| Changes in provisions for estimated losses | | 42,566 |
| | 301,871 |
| | (248,205 | ) | | 20,905 |
| | 42,566 |
| | 301,871 |
|
| Changes in other regulatory assets | | 262,317 |
| | (1,061,537 | ) | | 1,105,622 |
| | (48,469 | ) | | 262,317 |
| | (1,061,537 | ) |
| Changes in other regulatory liabilities | | 61,241 |
| | 87,654 |
| | 397,341 |
| | 158,031 |
| | 61,241 |
| | 87,654 |
|
| Changes in pensions and other postretirement liabilities | | (446,418 | ) | | 1,308,166 |
| | (1,433,663 | ) | | (136,919 | ) | | (446,418 | ) | | 1,308,166 |
|
| Other | | 134,344 |
| | (647,952 | ) | | 314,505 |
| | (421,676 | ) | | 134,344 |
| | (647,952 | ) |
| Net cash flow provided by operating activities | | 3,291,184 |
| | 3,889,561 |
| | 3,189,219 |
| | 2,998,699 |
| | 3,291,184 |
| | 3,889,561 |
|
| | | | | | | | | | | | | |
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction/capital expenditures | | (2,500,860 | ) | | (2,119,191 | ) | | (2,287,593 | ) | | (2,780,222 | ) | | (2,500,860 | ) | | (2,119,191 | ) |
| Allowance for equity funds used during construction | | 53,635 |
| | 68,375 |
| | 69,689 |
| | 68,345 |
| | 53,635 |
| | 68,375 |
|
| Nuclear fuel purchases | | (493,604 | ) | | (537,548 | ) | | (517,825 | ) | | (314,706 | ) | | (493,604 | ) | | (537,548 | ) |
| Payment for purchase of plant | | — |
| | — |
| | (17,300 | ) | | (949,329 | ) | | — |
| | — |
|
| Proceeds from sale of assets and businesses | | 487,406 |
| | 10,100 |
| | 147,922 |
| |
| Proceeds from sale of assets | | | — |
| | 487,406 |
| | 10,100 |
|
| Insurance proceeds received for property damages | | 24,399 |
| | 40,670 |
| | — |
| | 20,968 |
| | 24,399 |
| | 40,670 |
|
| Changes in securitization account | | (5,806 | ) | | 1,511 |
| | 155 |
| | 4,007 |
| | (5,806 | ) | | 1,511 |
|
| NYPA value sharing payment | | (70,790 | ) | | (72,000 | ) | | (71,736 | ) | | — |
| | (70,790 | ) | | (72,000 | ) |
| Payments to storm reserve escrow account | | (69,163 | ) | | (276,057 | ) | | (7,716 | ) | | (1,544 | ) | | (69,163 | ) | | (276,057 | ) |
| Receipts from storm reserve escrow account | | 5,916 |
| | — |
| | 260,279 |
| | — |
| | 5,916 |
| | — |
|
| Decrease (increase) in other investments | | 571 |
| | 46,983 |
| | (82,955 | ) | |
| Decrease in other investments | | | 9,055 |
| | 571 |
| | 46,983 |
|
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | 18,296 |
| | — |
| | 21,034 |
| | 169,085 |
| | 18,296 |
| | — |
|
| Proceeds from nuclear decommissioning trust fund sales | | 2,492,176 |
| | 1,872,115 |
| | 2,031,552 |
| | 2,408,920 |
| | 2,492,176 |
| | 1,872,115 |
|
| Investment in nuclear decommissioning trust funds | | (2,550,958 | ) | | (1,989,446 | ) | | (2,147,099 | ) | | (2,484,627 | ) | | (2,550,958 | ) | | (1,989,446 | ) |
| Net cash flow used in investing activities | | (2,608,782 | ) | | (2,954,488 | ) | | (2,601,593 | ) | | (3,850,048 | ) | | (2,608,782 | ) | | (2,954,488 | ) |
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| FINANCING ACTIVITIES | | | | | | | | | | | | |
| Proceeds from the issuance of: | | | | | | | | | | | | |
| Long-term debt | | 3,502,189 |
| | 3,100,069 |
| | 3,746,016 |
| | 6,800,558 |
| | 3,502,189 |
| | 3,100,069 |
|
| Preferred stock of subsidiary | | 107,426 |
| | — |
| | 24,249 |
| | — |
| | 107,426 |
| | — |
|
| Treasury stock | | 24,366 |
| | 194,866 |
| | 24,527 |
| | 33,114 |
| | 24,366 |
| | 194,866 |
|
| Retirement of long-term debt | | (3,461,518 | ) | | (2,323,313 | ) | | (3,814,666 | ) | | (5,311,324 | ) | | (3,461,518 | ) | | (2,323,313 | ) |
| Repurchase of common stock | | (99,807 | ) | | (183,271 | ) | | — |
| | — |
| | (99,807 | ) | | (183,271 | ) |
| Repurchase / redemptions of preferred stock | | (94,285 | ) | | — |
| | — |
| | (115,283 | ) | | (94,285 | ) | | — |
|
| Changes in credit borrowings and commercial paper - net | | (104,047 | ) | | (448,475 | ) | | 250,889 |
| | (79,337 | ) | | (104,047 | ) | | (448,475 | ) |
| Other | | (9,136 | ) | | 23,579 |
| | — |
| | (6,872 | ) | | (9,136 | ) | | 23,579 |
|
| Dividends paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common stock | | (598,897 | ) | | (596,117 | ) | | (593,037 | ) | | (611,835 | ) | | (598,897 | ) | | (596,117 | ) |
| Preferred stock | | (19,758 | ) | | (19,511 | ) | | (18,802 | ) | | (20,789 | ) | | (19,758 | ) | | (19,511 | ) |
| Net cash flow used in financing activities | | (753,467 | ) | | (252,173 | ) | | (380,824 | ) | |
| Net cash flow provided by (used in) financing activities | | | 688,232 |
| | (753,467 | ) | | (252,173 | ) |
| | | | | | | | | | | | | |
| Effect of exchange rates on cash and cash equivalents | | — |
| | — |
| | (245 | ) | |
| | | | | | | | | | | | | |
| Net increase (decrease) in cash and cash equivalents | | (71,065 | ) | | 682,900 |
| | 206,557 |
| | (163,117 | ) | | (71,065 | ) | | 682,900 |
|
| | | | | | | | | | | | | |
| Cash and cash equivalents at beginning of period | | 1,422,026 |
| | 739,126 |
| | 532,569 |
| | 1,350,961 |
| | 1,422,026 |
| | 739,126 |
|
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period | |
| $1,350,961 |
| |
| $1,422,026 |
| |
| $739,126 |
| |
| $1,187,844 |
| |
| $1,350,961 |
| |
| $1,422,026 |
|
| | | | | | | | | | | | | |
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $663,630 |
| |
| $611,376 |
| |
| $570,212 |
| |
| $746,779 |
| |
| $663,630 |
| |
| $611,376 |
|
| Income taxes | |
| $103,589 |
| |
| $77,799 |
| |
| $127,735 |
| |
| $95,317 |
| |
| $103,589 |
| |
| $77,799 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $63,497 |
| |
| $131,327 |
| |
| $129,579 |
| |
| $63,497 |
|
| Temporary cash investments | | 1,287,464 |
| | 1,290,699 |
| | 1,058,265 |
| | 1,287,464 |
|
| Total cash and cash equivalents | | 1,350,961 |
| | 1,422,026 |
| | 1,187,844 |
| | 1,350,961 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 608,491 |
| | 596,917 |
| | 654,995 |
| | 608,491 |
|
| Allowance for doubtful accounts | | (39,895 | ) | | (35,663 | ) | | (11,924 | ) | | (39,895 | ) |
| Other | | 178,364 |
| | 220,342 |
| | 158,419 |
| | 178,364 |
|
| Accrued unbilled revenues | | 321,940 |
| | 321,659 |
| | 368,677 |
| | 321,940 |
|
| Total accounts receivable | | 1,068,900 |
| | 1,103,255 |
| | 1,170,167 |
| | 1,068,900 |
|
| Deferred fuel costs | | — |
| | 155,140 |
| | 108,465 |
| | — |
|
| Accumulated deferred income taxes | | — |
| | 27,783 |
| |
| Fuel inventory - at average cost | | 217,810 |
| | 205,434 |
| | 179,600 |
| | 217,810 |
|
| Materials and supplies - at average cost | | 873,357 |
| | 918,584 |
| | 698,523 |
| | 873,357 |
|
| Deferred nuclear refueling outage costs | | 211,512 |
| | 214,188 |
| | 146,221 |
| | 211,512 |
|
| Prepayments and other | | 344,872 |
| | 343,223 |
| | 193,448 |
| | 344,872 |
|
| TOTAL | | 4,067,412 |
| | 4,389,633 |
| | 3,684,268 |
| | 4,067,412 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Investment in affiliates - at equity | | 4,341 |
| | 36,234 |
| | 198 |
| | 4,341 |
|
| Decommissioning trust funds | | 5,349,953 |
| | 5,370,932 |
| | 5,723,897 |
| | 5,349,953 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 219,999 |
| | 213,791 |
| | 233,641 |
| | 219,999 |
|
| Other | | 468,704 |
| | 405,169 |
| | 469,664 |
| | 468,704 |
|
| TOTAL | | 6,042,997 |
| | 6,026,126 |
| | 6,427,400 |
| | 6,042,997 |
|
| | | | | | | | | |
| PROPERTY, PLANT, AND EQUIPMENT | | |
| | |
| | |
| | |
|
| Electric | | 44,467,159 |
| | 44,881,419 |
| | 45,191,216 |
| | 44,467,159 |
|
| Property under capital lease | | 952,465 |
| | 945,784 |
| | 619,527 |
| | 952,465 |
|
| Natural gas | | 392,032 |
| | 377,565 |
| | 413,224 |
| | 392,032 |
|
| Construction work in progress | | 1,456,735 |
| | 1,425,981 |
| | 1,378,180 |
| | 1,456,735 |
|
| Nuclear fuel | | 1,345,422 |
| | 1,542,055 |
| | 1,037,899 |
| | 1,345,422 |
|
| TOTAL PROPERTY, PLANT AND EQUIPMENT | | 48,613,813 |
| | 49,172,804 |
| | 48,640,046 |
| | 48,613,813 |
|
| Less - accumulated depreciation and amortization | | 20,789,452 |
| | 20,449,858 |
| | 20,718,639 |
| | 20,789,452 |
|
| PROPERTY, PLANT AND EQUIPMENT - NET | | 27,824,361 |
| | 28,722,946 |
| | 27,921,407 |
| | 27,824,361 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 775,528 |
| | 836,064 |
| | 761,280 |
| | 775,528 |
|
| Other regulatory assets (includes securitization property of $714,044 as of December 31, 2015 and $724,839 as of December 31, 2014) | | 4,704,796 |
| | 4,968,553 |
| |
| Other regulatory assets (includes securitization property of $600,996 as of December 31, 2016 and $714,044 as of December 31, 2015) | | | 4,769,913 |
| | 4,704,796 |
|
| Deferred fuel costs | | 238,902 |
| | 238,102 |
| | 239,100 |
| | 238,902 |
|
| Goodwill | | 377,172 |
| | 377,172 |
| | 377,172 |
| | 377,172 |
|
| Accumulated deferred income taxes | | 54,903 |
| | 48,351 |
| | 117,885 |
| | 54,903 |
|
| Other | | 561,610 |
| | 807,508 |
| | 1,606,009 |
| | 561,610 |
|
| TOTAL | | 6,712,911 |
| | 7,275,750 |
| | 7,871,359 |
| | 6,712,911 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $44,647,681 |
| |
| $46,414,455 |
| |
| $45,904,434 |
| |
| $44,647,681 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $214,374 |
| |
| $899,375 |
| |
| $364,900 |
| |
| $214,374 |
|
| Notes payable and commercial paper | | 494,348 |
| | 598,407 |
| | 415,011 |
| | 494,348 |
|
| Accounts payable | | 1,071,798 |
| | 1,166,431 |
| | 1,285,577 |
| | 1,071,798 |
|
| Customer deposits | | 419,407 |
| | 412,166 |
| | 403,311 |
| | 419,407 |
|
| Taxes accrued | | 210,077 |
| | 128,108 |
| | 181,114 |
| | 210,077 |
|
| Accumulated deferred income taxes | | — |
| | 38,039 |
| |
| Interest accrued | | 194,565 |
| | 206,010 |
| | 187,229 |
| | 194,565 |
|
| Deferred fuel costs | | 235,986 |
| | 91,602 |
| | 102,753 |
| | 235,986 |
|
| Obligations under capital leases | | 2,709 |
| | 2,508 |
| | 2,423 |
| | 2,709 |
|
| Pension and other postretirement liabilities | | 62,513 |
| | 57,994 |
| | 76,942 |
| | 62,513 |
|
| Other | | 184,181 |
| | 248,251 |
| | 180,836 |
| | 184,181 |
|
| TOTAL | | 3,089,958 |
| | 3,848,891 |
| | 3,200,096 |
| | 3,089,958 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 8,306,865 |
| | 9,133,161 |
| | 7,495,290 |
| | 8,306,865 |
|
| Accumulated deferred investment tax credits | | 234,300 |
| | 247,521 |
| | 227,147 |
| | 234,300 |
|
| Obligations under capital leases | | 27,001 |
| | 29,710 |
| | 24,582 |
| | 27,001 |
|
| Other regulatory liabilities | | 1,414,898 |
| | 1,383,609 |
| | 1,572,929 |
| | 1,414,898 |
|
| Decommissioning and asset retirement cost liabilities | | 4,790,187 |
| | 4,458,296 |
| | 5,992,476 |
| | 4,790,187 |
|
| Accumulated provisions | | 460,727 |
| | 418,128 |
| | 481,636 |
| | 460,727 |
|
| Pension and other postretirement liabilities | | 3,187,357 |
| | 3,638,295 |
| | 3,036,010 |
| | 3,187,357 |
|
| Long-term debt (includes securitization bonds of $774,696 as of December 31, 2015 and $776,817 as of December 31, 2014) | | 13,111,556 |
| | 12,386,710 |
| |
| Long-term debt (includes securitization bonds of $661,175 as of December 31, 2016 and $774,696 as of December 31, 2015) | | | 14,467,655 |
| | 13,111,556 |
|
| Other | | 449,856 |
| | 557,649 |
| | 1,121,619 |
| | 449,856 |
|
| TOTAL | | 31,982,747 |
| | 32,253,079 |
| | 34,419,344 |
| | 31,982,747 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| Subsidiaries’ preferred stock without sinking fund | | 318,185 |
| | 210,760 |
| | 203,185 |
| | 318,185 |
|
| | | | | | | | | |
| EQUITY | | |
| | |
| |
| Common Shareholders’ Equity: | | |
| | |
| |
| Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2015 and in 2014 | | 2,548 |
| | 2,548 |
| |
| COMMON EQUITY | | | |
| | |
|
| Common stock, $.01 par value, authorized 500,000,000 shares; issued 254,752,788 shares in 2016 and in 2015 | | | 2,548 |
| | 2,548 |
|
| Paid-in capital | | 5,403,758 |
| | 5,375,353 |
| | 5,417,245 |
| | 5,403,758 |
|
| Retained earnings | | 9,393,913 |
| | 10,169,657 |
| | 8,195,571 |
| | 9,393,913 |
|
| Accumulated other comprehensive income (loss) | | 8,951 |
| | (42,307 | ) | | (34,971 | ) | | 8,951 |
|
| Less - treasury stock, at cost (76,363,763 shares in 2015 and 75,512,079 shares in 2014) | | 5,552,379 |
| | 5,497,526 |
| |
| Total common shareholders’ equity | | 9,256,791 |
| | 10,007,725 |
| |
| Subsidiaries’ preferred stock without sinking fund | | — |
| | 94,000 |
| |
| Less - treasury stock, at cost (75,623,363 shares in 2016 and 76,363,763 shares in 2015) | | | 5,498,584 |
| | 5,552,379 |
|
| TOTAL | | 9,256,791 |
| | 10,101,725 |
| | 8,081,809 |
| | 9,256,791 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $44,647,681 |
| |
| $46,414,455 |
| |
| $45,904,434 |
| |
| $44,647,681 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY CORPORATION AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | | | | | | | | |
| | |
| Common Shareholders’ Equity |
| | |
| Common Shareholders’ Equity |
| |
| | Subsidiaries’
Preferred
Stock | | Common Stock | | Treasury Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total | Subsidiaries’ Preferred Stock | | Common Stock | | Treasury Stock | | Paid-in Capital | | Retained Earnings | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2012 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,574,819 | ) | |
| $5,357,852 |
| |
| $9,704,591 |
| |
| ($293,083 | ) | |
| $9,291,089 |
| |
| | | | | | | | | | | | | | | |
| Consolidated net income (a) | 18,670 |
| | — |
| | — |
| | — |
| | 711,902 |
| | — |
| | 730,572 |
| |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 263,759 |
| | 263,759 |
| |
| Common stock issuances related to stock plans | — |
| | — |
| | 40,877 |
| | 10,279 |
| | — |
| | — |
| | 51,156 |
| |
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (591,440 | ) | | — |
| | (591,440 | ) | |
| Preferred dividend requirements of subsidiaries (a) | (18,670 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (18,670 | ) | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2013 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,533,942 | ) | |
| $5,368,131 |
| |
| $9,825,053 |
| |
| ($29,324 | ) | |
| $9,726,466 |
|
| $94,000 |
| |
| $2,548 |
| |
| ($5,533,942 | ) | |
| $5,368,131 |
| |
| $9,825,053 |
| |
| ($29,324 | ) | |
| $9,726,466 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (a) | 19,536 |
| | — |
| | — |
| | — |
| | 940,721 |
| | — |
| | 960,257 |
| 19,536 |
| | — |
| | — |
| | — |
| | 940,721 |
| | — |
| | 960,257 |
|
| Other comprehensive loss | — |
| | — |
| | — |
| | — |
| | — |
| | (12,983 | ) | | (12,983 | ) | — |
| | — |
| | — |
| | — |
| | — |
| | (12,983 | ) | | (12,983 | ) |
| Common stock repurchases | — |
| | — |
| | (183,271 | ) | | — |
| | — |
| | — |
| | (183,271 | ) | — |
| | — |
| | (183,271 | ) | | — |
| | — |
| | — |
| | (183,271 | ) |
| Common stock issuances related to stock plans | — |
| | — |
| | 219,687 |
| | 7,222 |
| | — |
| | — |
| | 226,909 |
| — |
| | — |
| | 219,687 |
| | 7,222 |
| | — |
| | — |
| | 226,909 |
|
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (596,117 | ) | | — |
| | (596,117 | ) | — |
| | — |
| | — |
| | — |
| | (596,117 | ) | | — |
| | (596,117 | ) |
| Preferred dividend requirements of subsidiaries (a) | (19,536 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,536 | ) | (19,536 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,536 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2014 |
| $94,000 |
| |
| $2,548 |
| |
| ($5,497,526 | ) | |
| $5,375,353 |
| |
| $10,169,657 |
| |
| ($42,307 | ) | |
| $10,101,725 |
|
| $94,000 |
| |
| $2,548 |
| |
| ($5,497,526 | ) | |
| $5,375,353 |
| |
| $10,169,657 |
| |
| ($42,307 | ) | |
| $10,101,725 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (loss) (a) | 19,828 |
| | — |
| | — |
| | — |
| | (176,562 | ) | | — |
| | (156,734 | ) | 19,828 |
| | — |
| | — |
| | — |
| | (176,562 | ) | | — |
| | (156,734 | ) |
| Other comprehensive income | — |
| | — |
| | — |
| | — |
| | — |
| | 51,258 |
| | 51,258 |
| — |
| | — |
| | — |
| | — |
| | — |
| | 51,258 |
| | 51,258 |
|
| Common stock repurchases | — |
| | — |
| | (99,807 | ) | | — |
| | — |
| | — |
| | (99,807 | ) | — |
| | — |
| | (99,807 | ) | | — |
| | — |
| | — |
| | (99,807 | ) |
| Preferred stock repurchases / redemptions | (94,000 | ) | | — |
| | — |
| | — |
| | (285 | ) | | — |
| | (94,285 | ) | (94,000 | ) | | — |
| | — |
| | — |
| | (285 | ) | | — |
| | (94,285 | ) |
| Common stock issuances related to stock plans | — |
| | — |
| | 44,954 |
| | 28,405 |
| | — |
| | — |
| | 73,359 |
| — |
| | — |
| | 44,954 |
| | 28,405 |
| | — |
| | — |
| | 73,359 |
|
| Common stock dividends declared | — |
| | — |
| | — |
| | — |
| | (598,897 | ) | | — |
| | (598,897 | ) | — |
| | — |
| | — |
| | — |
| | (598,897 | ) | | — |
| | (598,897 | ) |
| Preferred dividend requirements of subsidiaries (a) | (19,828 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,828 | ) | (19,828 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,828 | ) |
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at December 31, 2015 |
| $— |
| |
| $2,548 |
| |
| ($5,552,379 | ) | |
| $5,403,758 |
| |
| $9,393,913 |
| |
| $8,951 |
| |
| $9,256,791 |
|
| $— |
| |
| $2,548 |
| |
| ($5,552,379 | ) | |
| $5,403,758 |
| |
| $9,393,913 |
| |
| $8,951 |
| |
| $9,256,791 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Consolidated net income (loss) (a) | | 19,115 |
| | — |
| | — |
| | — |
| | (583,618 | ) | | — |
| | (564,503 | ) |
| Other comprehensive loss | | — |
| | — |
| | — |
| | — |
| | — |
| | (43,922 | ) | | (43,922 | ) |
| Common stock issuances related to stock plans | | — |
| | — |
| | 53,795 |
| | 13,487 |
| | — |
| | — |
| | 67,282 |
|
| Common stock dividends declared | | — |
| | — |
| | — |
| | — |
| | (611,835 | ) | | — |
| | (611,835 | ) |
| Subsidiaries' capital stock redemptions | | — |
| | — |
| | — |
| | — |
| | (2,889 | ) | | — |
| | (2,889 | ) |
| Preferred dividend requirements of subsidiaries (a) | | (19,115 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (19,115 | ) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2016 | |
| $— |
| |
| $2,548 |
| |
| ($5,498,584 | ) | |
| $5,417,245 |
| |
| $8,195,571 |
| |
| ($34,971 | ) | |
| $8,081,809 |
|
| | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| (a) Consolidated net income and preferred dividend requirements of subsidiaries for 2015, 2014, and 2013 include $14.9 million, $12.9 million, and $12 million, respectively, of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | |
| (a) Consolidated net income and preferred dividend requirements of subsidiaries include $19.1 million for 2016, $14.9 million for 2015, and $12.9 million for 2014 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. | | (a) Consolidated net income and preferred dividend requirements of subsidiaries include $19.1 million for 2016, $14.9 million for 2015, and $12.9 million for 2014 of preferred dividends on subsidiaries’ preferred stock without sinking fund that is not presented as equity. |
ENTERGY CORPORATION AND SUBSIDIARIES
NOTES TO FINANCIAL STATEMENTS
NOTE 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES (Entergy Corporation, Entergy Arkansas, 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 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 also maintain accounts in accordance with FERC and other regulatory guidelines.
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 Louisiana, Entergy Mississippi, and Entergy Texas generate, transmit, and distribute electric power primarily to retail customers in Arkansas, Louisiana, Mississippi, and Texas, respectively. Entergy 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, including Algiers. Prior to October 1, 2015, Entergy Louisiana was the electric power supplier for Algiers. 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.proceeding.
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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.
Accounting for MISO transactions
In December 2013, Entergy joined MISO, a regional transmission organization that maintains functional control over the combined transmission systems of its members and manages one of the largest energy markets in the U.S. In the MISO market, Entergy offers its generation and bids its load into the market on an hourly basis. MISO settles these hourly offers and bids based on locational marginal prices, which is pricing for energy at a given location based on a market clearing price that takes into account physical limitations on the transmission system, generation, and demand throughout the MISO region. MISO evaluates the market participants’ energy offers and demand bids to economically and reliably dispatch the entire MISO system. Entergy nets purchases and sales within the MISO market on an hourly basis and reports in operating revenues when in a net selling position and in operating expenses when in a net purchasing position.
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. In March 2016, Entergy Louisiana completed the first step in a two-step transaction to purchase the undivided interests in Waterford 3 that were previously being leased by acquiring a beneficial interest in the Waterford 3 leased assets. In February 2017 the leases were terminated and the leased assets transferred to Entergy Louisiana. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.
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, 20152016 and 2014,2015, is shown below:
| | | 2015 | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other | |
| 2016 | | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other |
| | | (In Millions) | | (In Millions) |
| Production | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Nuclear | |
| $8,672 |
| |
| $6,606 |
| |
| $2,066 |
| |
| $— |
| |
| $6,948 |
| |
| $6,524 |
| |
| $424 |
| |
| $— |
|
| Other | | 3,176 |
| | 3,127 |
| | 49 |
| | — |
| | 4,047 |
| | 4,000 |
| | 47 |
| | — |
|
| Transmission | | 4,431 |
| | 4,408 |
| | 23 |
| | — |
| | 5,226 |
| | 5,223 |
| | 3 |
| | — |
|
| Distribution | | 7,207 |
| | 7,207 |
| | — |
| | — |
| | 7,648 |
| | 7,648 |
| | — |
| | — |
|
| Other | | 1,536 |
| | 1,422 |
| | 111 |
| | 3 |
| | 1,636 |
| | 1,521 |
| | 111 |
| | 4 |
|
| Construction work in progress | | 1,457 |
| | 1,327 |
| | 130 |
| | — |
| | 1,378 |
| | 1,334 |
| | 44 |
| | — |
|
| Nuclear fuel | | 1,345 |
| | 857 |
| | 489 |
| | — |
| | 1,038 |
| | 817 |
| | 221 |
| | — |
|
| Property, plant, and equipment - net | |
| $27,824 |
| |
| $24,954 |
| |
| $2,868 |
| |
| $3 |
| |
| $27,921 |
| |
| $27,067 |
| |
| $850 |
| |
| $4 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other | |
| 2015 | | | Entergy | | Utility | | Entergy Wholesale Commodities | | Parent & Other |
| | | (In Millions) | | (In Millions) |
| Production | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Nuclear | |
| $9,639 |
| |
| $6,586 |
| |
| $3,053 |
| |
| $— |
| |
| $8,672 |
| |
| $6,606 |
| |
| $2,066 |
| |
| $— |
|
| Other | | 3,425 |
| | 3,067 |
| | 358 |
| | — |
| | 3,176 |
| | 3,127 |
| | 49 |
| | — |
|
| Transmission | | 4,197 |
| | 4,164 |
| | 33 |
| | — |
| | 4,431 |
| | 4,408 |
| | 23 |
| | — |
|
| Distribution | | 6,973 |
| | 6,973 |
| | — |
| | — |
| | 7,207 |
| | 7,207 |
| | — |
| | — |
|
| Other | | 1,521 |
| | 1,373 |
| | 145 |
| | 3 |
| | 1,536 |
| | 1,422 |
| | 111 |
| | 3 |
|
| Construction work in progress | | 1,426 |
| | 969 |
| | 456 |
| | 1 |
| | 1,457 |
| | 1,327 |
| | 130 |
| | — |
|
| Nuclear fuel | | 1,542 |
| | 840 |
| | 702 |
| | — |
| | 1,345 |
| | 857 |
| | 489 |
| | — |
|
| Property, plant, and equipment - net | |
| $28,723 |
| |
| $23,972 |
| |
| $4,747 |
| |
| $4 |
| |
| $27,824 |
| |
| $24,954 |
| |
| $2,868 |
| |
| $3 |
|
Depreciation rates on average depreciable property for Entergy approximated 2.8% in 2016, 2.9% in 2015, and 2.8% in 2014, and 2.6% in 2013.2014. Included in these rates are the depreciation rates on average depreciable Utility property of 2.6% in 2016, 2.7% in 2015, 2.5% in 2014, and 2.5% 2013,2014, and the depreciation rates on average depreciable Entergy Wholesale Commodities property of 5.2% in 2016, 5.4% in 2015, and 5.5% in 2014, and 4.1% in 2013. The increase in 2014 for Entergy Wholesale Commodities resulted from implementation of a new depreciation study.2014.
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 $163.8$169 million and $185.5$164 million as of December 31, 20152016 and 2014,2015, respectively.
Construction expenditures included in accounts payable is $234$253 million and $209$234 million at December 31, 20152016 and 2014,2015, 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, 20152016 and 2014,2015, is shown below:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) | | (In Millions) |
| Production | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear | |
| $1,192 |
| |
| $3,611 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,803 |
| |
| $1,201 |
| |
| $3,540 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,783 |
|
| Other | | 597 |
| | 1,551 |
| | 529 |
| | (13 | ) | | 463 |
| | — |
| | 801 |
| | 1,966 |
| | 537 |
| | 213 |
| | 483 |
| | — |
|
| Transmission | | 1,223 |
| | 1,693 |
| | 658 |
| | 65 |
| | 723 |
| | 46 |
| | 1,491 |
| | 1,925 |
| | 740 |
| | 79 |
| | 943 |
| | 45 |
|
| Distribution | | 1,997 |
| | 2,488 |
| | 1,166 |
| | 400 |
| | 1,156 |
| | — |
| | 2,144 |
| | 2,632 |
| | 1,242 |
| | 414 |
| | 1,216 |
| | — |
|
| Other | | 179 |
| | 483 |
| | 199 |
| | 184 |
| | 104 |
| | 17 |
| | 216 |
| | 517 |
| | 201 |
| | 188 |
| | 106 |
| | 25 |
|
| Construction work in progress | | 388 |
| | 421 |
| | 114 |
| | 29 |
| | 211 |
| | 93 |
| | 304 |
| | 670 |
| | 118 |
| | 25 |
| | 111 |
| | 44 |
|
| Nuclear fuel | | 286 |
| | 387 |
| | — |
| | — |
| | — |
| | 184 |
| | 307 |
| | 250 |
| | — |
| | — |
| | — |
| | 260 |
|
| Property, plant, and equipment - net | |
| $5,862 |
| |
| $10,634 |
| |
| $2,666 |
| |
| $665 |
| |
| $2,657 |
| |
| $2,143 |
| |
| $6,464 |
| |
| $11,500 |
| |
| $2,838 |
| |
| $919 |
| |
| $2,859 |
| |
| $2,157 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) | | (In Millions) |
| Production | | | | | | | | | | | | | | | | | | | | | | | | |
| Nuclear | |
| $1,097 |
| |
| $3,554 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,935 |
| |
| $1,192 |
| |
| $3,611 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $1,803 |
|
| Other | | 593 |
| | 1,561 |
| | 526 |
| | (11 | ) | | 399 |
| | — |
| | 597 |
| | 1,551 |
| | 529 |
| | (13 | ) | | 463 |
| | — |
|
| Transmission | | 1,166 |
| | 1,570 |
| | 642 |
| | 54 |
| | 695 |
| | 48 |
| | 1,223 |
| | 1,693 |
| | 658 |
| | 65 |
| | 723 |
| | 46 |
|
| Distribution | | 1,928 |
| | 2,447 |
| | 1,125 |
| | 407 |
| | 1,116 |
| | — |
| | 1,997 |
| | 2,488 |
| | 1,166 |
| | 400 |
| | 1,156 |
| | — |
|
| Other | | 164 |
| | 460 |
| | 194 |
| | 182 |
| | 98 |
| | 17 |
| | 179 |
| | 483 |
| | 199 |
| | 184 |
| | 104 |
| | 17 |
|
| Construction work in progress | | 284 |
| | 369 |
| | 68 |
| | 19 |
| | 125 |
| | 50 |
| | 388 |
| | 421 |
| | 114 |
| | 29 |
| | 211 |
| | 93 |
|
| Nuclear fuel | | 294 |
| | 295 |
| | — |
| | — |
| | — |
| | 251 |
| | 286 |
| | 387 |
| | — |
| | — |
| | — |
| | 184 |
|
| Property, plant, and equipment - net | |
| $5,526 |
| |
| $10,256 |
| |
| $2,555 |
| |
| $651 |
| |
| $2,433 |
| |
| $2,301 |
| |
| $5,862 |
| |
| $10,634 |
| |
| $2,666 |
| |
| $665 |
| |
| $2,657 |
| |
| $2,143 |
|
Depreciation rates on average depreciable property for the Registrant Subsidiaries are shown below:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| 2016 | | 2.5% | | 2.3% | | 3.1% | | 3.4% | | 2.5% | | 2.8% |
| 2015 | 2.6% | | 2.3% | | 3.2% | | 3.0% | | 2.6% | | 2.8% | 2.6% | | 2.3% | | 3.2% | | 3.0% | | 2.6% | | 2.8% |
| 2014 | 2.4% | | 2.2% | | 2.6% | | 3.2% | | 2.5% | | 3.0% | 2.4% | | 2.2% | | 2.6% | | 3.2% | | 2.5% | | 3.0% |
| 2013 | 2.5% | | 2.2% | | 2.6% | | 3.3% | | 2.5% | | 2.8% | |
Non-utility property - at cost (less accumulated depreciation) for Entergy Louisiana is reported net of accumulated depreciation of $150.1$154.4 million and $154.2$150.1 million as of December 31, 20152016 and 2014,2015, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Mississippi is reported net of accumulated depreciation of $0.5 million and $2.2$0.5 million as of December 31, 20152016 and 2014,2015, respectively. Non-utility property - at cost (less accumulated depreciation) for Entergy Texas is reported net of accumulated depreciation of $4.9 million and $10.4$4.9 million as of December 31, 20152016 and 2014,2015, respectively.
As of December 31, 2016, construction expenditures included in accounts payable are $40.9 million for Entergy Arkansas, $114.8 million for Entergy Louisiana, $11.5 million for Entergy Mississippi, $2.3 million for Entergy New Orleans, $9.3 million for Entergy Texas, and $6.2 million for System Energy. As of December 31, 2015, construction expenditures included in accounts payable are $43 million for Entergy Arkansas, $68.6 million for Entergy Louisiana, $11.4 million for Entergy Mississippi, $1.5 million for Entergy New Orleans, $33.1 million for Entergy Texas, and $6.8 million for System Energy. As of December 31, 2014, construction expenditures included in accounts payable are $37.3 million for Entergy Arkansas, $71.4 million for Entergy Louisiana, $7.8 million for Entergy Mississippi, $0.9 million for Entergy New Orleans, $24.1 million for Entergy Texas, and $7.7 million for System Energy.
Jointly-Owned Generating Stations
Certain Entergy subsidiaries jointly own electric generating facilities with affiliates or third parties. All parties are required to provide their own financing. The investments, fuel expenses, and other operation and maintenance 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, 2015,2016, 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 | Generating Stations | | Fuel-Type | | Total Megawatt Capability (a) | | Ownership | | Investment | | Accumulated Depreciation | Generating Stations | | Fuel Type | | Total Megawatt Capability (a) | | Ownership | | Investment | | Accumulated Depreciation |
| | | | | | | | | | | (In Millions) | | | | | | | | | | (In Millions) |
| Utility business: | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas - | | | | | | | | | | | | | | | | | | | | | | | | |
| Independence | | Unit 1 | | Coal | | 839 |
| | 31.50 | % | |
| $134 |
| |
| $100 |
| | Unit 1 | | Coal | | 839 |
| | 31.50 | % | |
| $134 |
| |
| $103 |
|
| | | Common Facilities | | Coal | | | | 15.75 | % | |
| $33 |
| |
| $26 |
| |
| Independence | | | Common Facilities | | Coal | | | | 15.75 | % | |
| $34 |
| |
| $27 |
|
| White Bluff | | Units 1 and 2 | | Coal | | 1,637 |
| | 57.00 | % | |
| $520 |
| |
| $361 |
| | Units 1 and 2 | | Coal | | 1,635 |
| | 57.00 | % | |
| $521 |
| |
| $365 |
|
| Ouachita (b) | | Common
Facilities | | Gas | | 489 |
| | 66.67 | % | |
| $170 |
| |
| $147 |
| | Common Facilities | | Gas | | 493 |
| | 66.67 | % | |
| $172 |
| |
| $148 |
|
| Union (c) | | | Units 1 and 2 Common Facilities | | Gas | |
|
| | 50.00 | % | |
| $1 |
| |
| $— |
|
| Union (c) | | | Common Facilities | | Gas | | | | 25.00 | % | |
| $25 |
| |
| $1 |
|
| Entergy Louisiana - | | | | | | | | |
| | | | | | | | | | | | |
| | | | |
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 40.25 | % | |
| $274 |
| |
| $185 |
| | Unit 6 | | Coal | | 550 |
| | 40.25 | % | |
| $277 |
| |
| $189 |
|
| Roy S. Nelson | | Unit 6 Common
Facilities | | Coal | | | | 17.26 | % | |
| $11 |
| |
| $5 |
| | Unit 6 Common Facilities | | Coal | | | | 18.65 | % | |
| $14 |
| |
| $6 |
|
| Big Cajun 2 | | Unit 3 | | Coal | | 594 |
| | 24.15 | % | |
| $151 |
| |
| $109 |
| | Unit 3 | | Coal | | 588 |
| | 24.15 | % | |
| $150 |
| |
| $113 |
|
| Big Cajun 2 | | | Unit 3 Common Facilities | | Coal | | | | 8.05 | % | |
| $5 |
| |
| $2 |
|
| Ouachita (b) | | Common
Facilities | | Gas | | 243 |
| | 33.33 | % | |
| $87 |
| |
| $74 |
| | Common Facilities | | Gas | | 248 |
| | 33.33 | % | |
| $90 |
| |
| $75 |
|
| Acadia | | Common
Facilities | | Gas | | 551 |
| | 50.00 | % | |
| $19 |
| |
| $— |
| | Common Facilities | | Gas | | 557 |
| | 50.00 | % | |
| $19 |
| |
| $— |
|
| Union (c) | | | Common Facilities | | Gas | | | | 50.00 | % | |
| $50 |
| |
| $1 |
|
| Entergy Mississippi - | | | | | | | | |
| | | | | | | | | | | | |
| | | | |
| Independence | | Units 1 and 2
and Common
Facilities | | Coal | | 1,681 |
| | 25.00 | % | |
| $258 |
| |
| $152 |
| | Units 1 and 2 and Common Facilities | | Coal | | 1,681 |
| | 25.00 | % | |
| $257 |
| |
| $155 |
|
| Entergy New Orleans - | | | | | | | | | |
| Union (c) | | | Units 1 and 2 Common Facilities | | Gas | |
|
| | 50.00 | % | |
| $1 |
| |
| $— |
|
| Union (c) | | | Common Facilities | | Gas | | | | 25.00 | % | |
| $25 |
| |
| $1 |
|
| Entergy Texas - | | | | | | | | |
| | | | | | | | | | | | |
| | | | |
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 29.75 | % | |
| $197 |
| |
| $114 |
| | Unit 6 | | Coal | | 550 |
| | 29.75 | % | |
| $198 |
| |
| $113 |
|
| Roy S. Nelson | | Unit 6 Common
Facilities | | Coal | | | | 12.75 | % | |
| $6 |
| |
| $2 |
| | Unit 6 Common Facilities | | Coal | | | | 13.79 | % | |
| $6 |
| |
| $2 |
|
| Big Cajun 2 | | | Unit 3 | | Coal | | 588 |
| | 17.85 | % | |
| $113 |
| |
| $74 |
|
| Big Cajun 2 | | Unit 3 | | Coal | | 594 |
| | 17.85 | % | |
| $113 |
| |
| $73 |
| | Unit 3 Common Facilities | | Coal | | | | 5.95 | % | |
| $3 |
| |
| $1 |
|
| System Energy - | | | | | | | | |
| | | | | | | | | | | | |
| | | | |
| Grand Gulf | | Unit 1 | | Nuclear | | 1,409 |
| | 90.00 | % | (c) | |
| $4,829 |
| |
| $2,962 |
| | Unit 1 | | Nuclear | | 1,401 |
| | 90.00 | % | (d) |
| $4,917 |
| |
| $3,063 |
|
Entergy Wholesale Commodities: | | | | | | | | |
| | | | | | | | | | | | |
| | | | |
| Independence | | Unit 2 | | Coal | | 842 |
| | 14.37 | % | |
| $71 |
| |
| $47 |
| | Unit 2 | | Coal | | 842 |
| | 14.37 | % | |
| $71 |
| |
| $49 |
|
| Independence | | Common
Facilities | | Coal | | | | 7.18 | % | |
| $16 |
| |
| $11 |
| | Common Facilities | | Coal | | | | 7.18 | % | |
| $16 |
| |
| $12 |
|
| Roy S. Nelson | | Unit 6 | | Coal | | 537 |
| | 10.90 | % | |
| $111 |
| |
| $58 |
| | Unit 6 | | Coal | | 550 |
| | 10.90 | % | |
| $112 |
| |
| $60 |
|
| Roy S. Nelson | | Unit 6 Common Facilities | | Coal | | | | 4.67 | % | |
| $2 |
| |
| $1 |
| | Unit 6 Common Facilities | | Coal | | | | 5.05 | % | |
| $2 |
| |
| $1 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | “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. |
| |
| (b) | Ouachita Units 1 and 2 are owned 100% by Entergy Arkansas and Ouachita Unit 3 is owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the common facilities and not for the generating units. |
| |
| (c) | Union Unit 1 is owned 100% by Entergy New Orleans, Union Unit 2 is owned 100% by Entergy Arkansas, Union Units 3 and 4 are owned 100% by Entergy Louisiana. The investment and accumulated depreciation numbers above are only for the specified common facilities and not for the generating units. |
| |
| (d) | Includes a leasehold interest held by System Energy. System Energy’s Grand Gulf lease obligations are discussed in Note 10 to the financial statements. |
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. Because the value of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, in the future the Entergy Wholesale Commodities nuclear plants will charge nuclear refueling outage costs directly to expense when incurred.
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. Entergy Louisiana, LLC is not a member of the Entergy Corporation federal tax filing group but, rather, is included in the Entergy Utility Holding Company, LLC consolidated federal income tax filing group. 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.agreements. Deferred income taxes are recorded for temporary differences between the book and tax basis of assets and liabilities, and for certain losses and 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.
Effective December 31, 2015, Entergy prospectively adopted ASU 2015-17, which simplifies the presentation of deferred taxes. Beginning with the December 31, 2015 balances, all deferred taxes will be classified as non-current. Periods prior to December 31, 2015 were not retrospectively adjusted.
The benefits of investment tax credits are deferred and amortized over the average useful life of the related property, as a reduction of income tax expense, for such credits associated with regulated operations in accordance with ratemaking treatment.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Earnings (Loss) per Share
The following table presents Entergy’s basic and diluted earnings per share calculation included on the consolidated statements of operations:
| | | | For the Years Ended December 31, | For the Years Ended December 31, |
| | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Millions, Except Per Share Data) | (In Millions, Except Per Share Data) |
| | | | $/share | | | | $/share | | | | $/share | | | $/share | | | | $/share | | | | $/share |
| Net income (loss) attributable to Entergy Corporation |
| ($176.6 | ) | | |
| |
| $940.7 |
| | |
| |
| $711.9 |
| | |
|
| ($583.6 | ) | | |
| |
| ($176.6 | ) | | |
| |
| $940.7 |
| | |
|
| Basic earnings (loss) per average common share | 179.2 |
| |
| ($0.99 | ) | | 179.5 |
| |
| $5.24 |
| | 178.2 |
| |
| $3.99 |
| 178.9 |
| |
| ($3.26 | ) | | 179.2 |
| |
| ($0.99 | ) | | 179.5 |
| |
| $5.24 |
|
| Average dilutive effect of: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Stock options | — |
| | — |
| | 0.3 |
| | (0.01 | ) | | 0.1 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 0.3 |
| | (0.01 | ) |
| Other equity plans | — |
| | — |
| | 0.5 |
| | (0.01 | ) | | 0.3 |
| | — |
| — |
| | — |
| | — |
| | — |
| | 0.5 |
| | (0.01 | ) |
| Diluted earnings (loss) per average common shares | 179.2 |
| |
| ($0.99 | ) | | 180.3 |
| |
| $5.22 |
| | 178.6 |
| |
| $3.99 |
| 178.9 |
| |
| ($3.26 | ) | | 179.2 |
| |
| ($0.99 | ) | | 180.3 |
| |
| $5.22 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The calculation of diluted earnings (loss) per share excluded 7,137,210 options outstanding at December 31, 2016, 7,399,820 options outstanding at December 31, 2015, and 5,743,013 options outstanding at December 31, 2014 and 8,866,542 options outstanding at December 31, 2013.because they were antidilutive.
Stock-based Compensation Plans
Entergy grants stock options, restricted stock, performance units, and restricted stock unit 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 3 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 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, unless specific cost
Entergy Corporation and Subsidiaries
Notes to Financial Statements
recovery is 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 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 customers and shareholders.
Regulatory Asset for Income Taxes
Accounting standards for income taxes provide that a regulatory asset or liability be recorded if it is probable that the currently determinable future increase or decrease in regulatory income tax expense will be recovered from or reimbursed to customers through future rates. The primary source of Entergy’s regulatory asset for income taxes is related to the ratemaking treatment of the tax effects of book depreciation for the equity component of AFUDC that has been capitalized to property, plant, and equipment but for which there is no corresponding tax basis. Equity-AFUDC is a component of property, plant, and equipment that is included in rate base when the plant is placed in service.
Cash and Cash Equivalents
Entergy considers all unrestricted highly liquid debt instruments with an original maturity of three months or less at date of purchase to be cash equivalents.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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.
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 record an offsetting amount in other regulatory liabilities/assets for the unrealized gains/(losses) on investment securities. For the 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana has recorded an offsetting amount in other deferred credits for the unrealized gains/(losses). Decommissioning trust funds for Pilgrim, Indian Point 1, andIndian 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. 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 1716 to the financial statements for details on the decommissioning trust funds.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 the investee’s comprehensive earnings and losses in income and as an increase or decrease to the investment account. Any cash distributions are charged against the investment account. 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 sale 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. Due to regulatory treatment, an offsetting regulatory asset or liability is recorded for changes in fair value of recognized derivatives for the Registrant Subsidiaries.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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. Changes in the fair value of derivative instruments that are not designated as cash flow hedges are recorded in current-period earnings on a mark-to-market basis.
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. See Note 15 to the financial statements for further details on Entergy’s derivative instruments and hedging activities.
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and 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 held by regulated businesses may be reflected in future rates and therefore do not affect net income. 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 1615 to the financial statements for further discussion of fair value.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Impairment of Long-LivedLong-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 expected operating life of the assets, 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 and capacity over the remaining life of the assets.
Two nuclear power plants Because the values of their long-lived assets are impaired, and their remaining estimated operating lives significantly reduced, in the future the Entergy Wholesale Commodities business segment (Indian Point 2 and Indian Point 3) have an application pendingnuclear plants will charge expenditures for renewed NRC licenses. Various parties have expressed oppositioncapital assets directly to renewalexpense when incurred. See Note 14 to the financial statements for further discussions of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule. If the NRC does not renew the operating license for either of these plants, the plant’s operating life could be shortened, reducing its projected net cash flows and potentially impairing its value as an asset.
Entergy determined in October 2015 that it will close FitzPatrick at the end of its current fuel cycle, which is planned for January 27, 2017, because of poor market conditions that have led to reduced revenues, a poor market
Entergy Corporation and Subsidiaries
Notes to Financial Statements
design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant, as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.
Entergy determined in October 2015 that it will close Pilgrim no later than June 1, 2019 because of poor market conditions that have led to reduced revenues, a poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in Column 4 of the Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.
Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities business, Palisades and Indian Point, in the fourth quarter 2015. For purposes of that evaluation, Entergy considered a number of factors associated with the facilities’ continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and the supply region in which the nuclear facilities sell energy and capacity.
Under generally accepted accounting principles the determination of an asset’s 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 operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.
The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of September 30, 2015.
The test for Palisades indicated the probability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.
The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point was not impaired as of December 31, 2015. As of December 31, 2015, the net carrying value of Indian Point, including nuclear fuel, is $2,360 million.
As a result of the impairment analyses, Entergy recognized non-cash impairment and other related charges of $1,642 million ($1,062 million net-of-tax) during the third quarter 2015 to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In the fourth quarter 2015, Entergy recognized non-cash impairment and other related charges of $396 million ($256 million net-of-tax) to write down the carrying value of the Palisades plant and related assets to their fair values, as well as additional charges related to the plant closure decisions at FitzPatrick and Pilgrim. Entergy performed fair value analyses based on the income approach, a discounted cash flow method, to determine the amount of impairment.
The estimated fair value of the FitzPatrick plant and related long-lived assets is $29 million, while the carrying value was $742 million, resulting in an impairment charge of $713 million. Materials and supplies were evaluated and written down by $48 million. In addition, FitzPatrick has a contract asset recorded for an agreement between Entergy subsidiaries and NYPA entered when Entergy subsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. NYPA has the right to require the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If the decommissioning liabilities are retained by NYPA, the Entergy subsidiaries will perform the decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represents an estimate of the present value of the difference between the Entergy subsidiaries’ stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, the impairment and related charges for FitzPatrick total $965 million ($624 million net-of-tax).
The estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by$24 million. In summary, the total impairment loss and related charges for Pilgrim is $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a $134 million increase in Pilgrim’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows.
The estimated fair value of the Palisades plant and related long-lived assets is $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis.
In August 2013, the Board approved a plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. The decision to shut down the plant was primarily due to sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the region in which the plant operates.
As a result of the decision to shut down the plant, Entergy recognized non-cash impairment and other related charges of $291.5 million ($183.7 million net-of-tax) during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. 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 was $62 million, while the carrying value was $349 million. The carrying value of $349 million reflected the effect of a $58 million increase in Vermont Yankee’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations.
As a result of a settlement agreement entered into in 2013 by Entergy and Vermont regarding the remaining operation and decommissioning of Vermont Yankee, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows for Vermont Yankee. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in December 2013. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014. Impairment charges are recorded as a separate line item in Entergy’s consolidated statements of income for 2014 and 2013, and this impairment charge is included within the resultsimpairments of the Entergy Wholesale Commodities segment.nuclear plants.
The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition
Entergy Corporation and Subsidiaries
Notes to Financial Statements
to the impairments and other related charges, Entergy incurred $46 million in 2014 and $8 million in 2015, and expects to incur additional charges from 2016 into mid-2019 estimated to be up to approximately $175 million for severance and employee retention costs relating to the decisions to shut down Vermont Yankee, FitzPatrick, and Pilgrim.
The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of the FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets to a market participant. In order to determine these prices, 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 plants and related assets as well as the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs. 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, are 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 FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets:
|
| | | | |
| Significant Unobservable Inputs | | Amount | | Weighted Average |
| | | | | |
| Weighted average cost of capital | | | | |
| FitzPatrick | | 7.5% | | 7.5% |
| Pilgrim (a) | | 7.5%-8.0% | | 7.9% |
| Palisades | | 7.5% | | 7.5% |
| Vermont Yankee | | 7.5% | | 7.5% |
| | | | | |
| Long-term pre-tax operating margin (cash basis) | | | | |
| FitzPatrick | | 10.2% | | 10.2% |
| Pilgrim (a) | | 2.4%-10.6% | | 8.1% |
| Palisades (b) | | 30.8% | | 30.8% |
| Vermont Yankee | | 7.0% | | 7.0% |
(a) The fair value of Pilgrim was based on the probability weighting of two potential scenarios.
| |
(b) | Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that expires in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022. |
Entergy’s Accounting Policy group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Pilgrim, Palisades, and Vermont Yankee plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.
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 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 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.
Debt Issuance Costs
In the fourth quarter 2015, Entergy adopted ASU No. 2015-03 “Interest-Imputation of Interest (Subtopic 835-30): Simplifying the Presentation of Debt Issuance Costs” and ASU No. 2015-15 “Interest-Imputation of Interest (Subtopic 835-30): Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements.”
For all periods presented in this report, debt issuance costs related to a note are reported in the balance sheet as a reduction of the carrying value of the related debt, and debt issuance costs related to revolving credit facilities are reported in Other deferred debits separately from the amounts owed under such facility. Prior to adoption, Entergy reported both types of debt issuance costs in Other deferred debits. The change resulted in a reduction of both Other deferred debits and Long-term debt for all prior periods presented.
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 Louisiana, a limited liability company, had outstanding preferred securities with similar protective rights with respect to unpaid dividends, but provided for the election of board members that would not constitute a majority of the board; and its preferred securities were therefore classified as a component of members’ equity. In September 2015, Entergy Louisiana redeemed or repurchased and canceled its preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana business combination. See Note 2 to the financial statements for a discussion of the business combination.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The outstanding preferred securities of Entergy Arkansas, Entergy Mississippi, and Entergy New Orleans, and Entergy Utility Holding Company (a Utility subsidiary) and Entergy Finance Holding (an Entergy Wholesale Commodities subsidiary), whose preferred holders also have protective rights, are similarly presented between liabilities and equity on Entergy’s consolidated balance sheets and the outstanding preferred securities of 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. Final pronouncements that result from these projects could have a material effect on Entergy’s future net income, financial position, or cash flows.
In May 2014 the FASB issued ASU No. 2014-09, “Revenue from Contracts with Customers (Topic 606).” The ASU’s core principle is that “an entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services.” The ASU details a five-step model that should be followed to achieve the core principle. In August 2015, theWith FASB issuedissuance of ASU No. 2015-14, “Revenue from Contracts with Customers (Topic 606): Deferral of the Effective Date” which deferred the effective date of ASU 2014-09 for all entities by one year. Accordingly,Date,” ASU 2014-09 is effective for Entergy for the first quarter 2018. Entergy does not expectis evaluating its transition approach (which will either be a full retrospective or a modified retrospective transition method) and the effects of the new guidance, most significantly on its accounting for contributions in aid of construction. Entergy’s evaluation of ASU 2014-09 tohas not identified any effects that it expects will affect materially its results of operations, financial position, or cash flows. Entergy will continue to monitor, however, the development of industry specific application guidance that could have an effect on this assessment.
In November 2014 the FASB issued ASU No. 2014-16, “Derivatives and Hedging (Topic 815): Determining Whether the Host Contract in a Hybrid Financial Instrument Issued in the Form of a Share Is More Akin to Debt or to Equity.” The ASU states that for hybrid financial instruments issued in the form of a share, an entity should determine the nature of the host contract by considering all stated and implied substantive terms and features of the hybrid financial instrument, weighing each term and feature on the basis of relevant facts and circumstances. ASU 2014-16 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2014-16 to affect materially its results of operations, financial position, or cash flows.
In February 2015 the FASB issued ASU No. 2015-02, “Consolidation (Topic 810): Amendments to the Consolidation Analysis” which changes the analysis that a reporting entity must perform to determine whether it should consolidate certain types of legal entities. The ASU affects (1) limited partnerships and similar legal entities, (2) evaluating fees paid to a decision maker or a service provider as a variable interest, (3) the effect of fee arrangements on the primary beneficiary determination, (4) the effect of related parties on the primary beneficiary determination, and (5) certain investment funds. ASU 2015-02 is effective for Entergy for the first quarter 2016. Entergy does not expect ASU 2015-02 to affect materially its results of operations, financial position, or cash flows.
In January 2016 the FASB issued ASU No. 2016-01 “Financial Instruments (Subtopic 825-10): Recognition and Measurement of Financial Assets and Financial Liabilities.” The ASU requires investments in equity investments,securities, excluding those accounted for under the equity method or resulting in consolidation of the investee, to be measured at fair value with changes recognized in net income. The ASU requires a qualitative assessment to identify impairments of investments in equity investments withoutsecurities that do not have a readily determinable fair value. ASU 2016-01 is effective for Entergy for the first quarter 2018. Entergy expects that ASU 2016-01 will affect its results of operations by requiring unrealized gains and losses on investments in equity investmentssecurities held by the nuclear decommissioning trust funds to be recorded in earnings rather than in other comprehensive income. In accordance with the regulatory treatment of the decommissioning trust funds of Entergy Arkansas, Entergy Louisiana, and System Energy, an offsetting amount of unrealized gains/losses will continue to be recorded in other regulatory liabilities/assets. Entergy is evaluating the ASU for other effects on the results of operations, financial position, and cash flows.
Entergy Louisiana Basis of Presentation
As discussed in more detail in Note 2 toIn February 2016 the financial statements, on October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all ofFASB issued ASU No. 2016-02, “Leases (Topic 842).” The ASU’s core principle is that “a lessee should recognize the assets and has assumedliabilities that arise from leases.” The ASU considers that “all leases create an asset and a liability,” and accordingly requires recording the assets and liabilities related to all leases with a term greater than 12 months. ASU 2016-02 is effective for Entergy for the first quarter 2019, with early adoption permitted. Entergy expects that ASU 2016-02 will affect its financial position by increasing the assets and liabilities recorded relating to its operating leases. Entergy is evaluating ASU 2016-02 for other effects on its results of Old Entergy Louisianaoperations, financial position, and Old Entergy Gulf States Louisiana.cash flows, as well as the potential to early adopt the ASU.
In March 2016 the FASB issued ASU No. 2016-09, “Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting.” The combination was accounted for as a transaction between entities under common control. The effectASU seeks to simplify several aspects of the business combination has been retrospectively appliedaccounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows. The statement is effective beginning in 2017 and Entergy will prospectively recognize all income tax effects related to share-based payments through the income statement. Entergy Louisiana'sexpects to record approximately $12 million in income tax expense in the first quarter of 2017 related to implementing ASU 2016-09.
In June 2016 the FASB issued ASU No. 2016-13, “Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments.” The ASU requires entities to record a valuation allowance on financial statementsinstruments recorded at amortized cost or classified as available-for-sale debt securities for the total credit losses expected over the life of the instrument. Increases and decreases in the valuation allowance will be recognized
Entergy Corporation and Subsidiaries
Notes to Financial Statements
that are presentedimmediately in this report.earnings. ASU 2016-13 is effective for Entergy for the first quarter 2020. Entergy is evaluating ASU 2016-13 for the expected effects on its results of operations, financial position, and cash flows.
Entergy New Orleans BasisIn October 2016 the FASB issued ASU No. 2016-16, “Income Taxes (Topic 740): Intra-Entity Transfers of Presentation
On September 1, 2015, Entergy Louisiana transferred its Algiers assetsAssets Other Than Inventory.” The ASU requires entities to Entergy New Orleans for a purchase pricerecognize the income tax consequences of approximately $85 million, subject to closing adjustments. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million. Because theintra-entity asset transfer was a transaction involving entities under common control, Entergy New Orleans recognized the assets and liabilities transferred to it at their carrying amounts in the accounts of Entergy Louisianatransfers, other than inventory, at the time the transfer occurs. ASU 2016-16 is effective for Entergy for the first quarter 2018 and will affect its statement of thefinancial position by requiring recognition of deferred tax assets or liabilities arising from intra-entity asset transfer. The effecttransfers. Entergy is evaluating ASU 2016-16 for other effects on its results of the Algiers transfer has been retrospectively applied to Entergy New Orleans’soperations, financial statements that are presented in this report.position, and cash flows.
NOTE 2. RATE AND REGULATORY MATTERS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Regulatory Assets and Regulatory Liabilities
Regulatory assets represent probable future revenues associated with costs that Entergy expects to recover from customers through the regulatory ratemaking process under which the Utility business operates. Regulatory liabilities represent probable future reductions in revenues associated with amounts that Entergy expects to benefit customers through the regulatory ratemaking process under which the Utility business operates. In addition to the regulatory assets and liabilities that are specifically disclosed on the face of the balance sheets, the tables below provide detail of “Other regulatory assets” and “Other regulatory liabilities” that are included on Entergy’s and the Registrant Subsidiaries’ balance sheets as of December 31, 20152016 and 2014:2015:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Regulatory Assets
Entergy
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $2,574.9 |
| |
| $2,798.8 |
|
| $2,635.5 |
| |
| $2,574.9 |
|
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5 - Entergy Arkansas Securitization Bonds) | 717.8 |
| | 736.2 |
| |
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b) | 589.1 |
| | 513.8 |
| |
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | | 677.2 |
| | 589.1 |
|
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 – Storm Cost Recovery Filings with Retail Regulators) (Note 5) | | 637.0 |
| | 717.8 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 273.3 |
| | 245.1 |
| 353.9 |
| | 273.3 |
|
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | 121.1 |
| | 139.2 |
| 100.0 |
| | 121.1 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 66.7 |
| | 76.2 |
| 91.4 |
| | 66.7 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 57.4 |
| | 66.2 |
| 47.9 |
| | 57.4 |
|
New nuclear generation development costs (Note 2 - New Nuclear Generation Development Costs) (c)(b) | 51.1 |
| | 58.4 |
| 43.7 |
| | 51.1 |
|
MISO implementation costs - recovery through retail rate riders (Note 2 - Retail Rate Proceedings) | 49.4 |
| | 69.6 |
| |
MISO costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings) | | 36.2 |
| | 65.2 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined by retail regulators | 32.2 |
| | 54.7 |
| 22.1 |
| | 32.2 |
|
Human capital management costs - recovery through retail rate mechanisms (Note 2 - Retail Rate Proceedings) | 28.3 |
| | 42.3 |
| 17.3 |
| | 28.3 |
|
| Other | 143.5 |
| | 168.1 |
| 107.7 |
| | 127.7 |
|
| Entergy Total |
| $4,704.8 |
| |
| $4,968.6 |
|
| $4,769.9 |
| |
| $4,704.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) |
| $766.5 |
| |
| $838.2 |
|
| $786.6 |
| |
| $766.5 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b)(a) | 288.0 |
| | 254.8 |
| 322.9 |
| | 288.0 |
|
Storm damage costs - recovered either through securitization or retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) (Note 5 - Entergy Arkansas Securitization Bonds) | 97.2 |
| | 125.6 |
| |
Removal costs - recovered through depreciation rates (Note 9) (b) | 85.7 |
| | 59.0 |
| |
Removal costs - recovered through depreciation rates (Note 9) (a) | | 128.5 |
| | 85.7 |
|
Storm damage costs - recovered either through securitization or retail rates (Note 5 - Entergy Arkansas Securitization Bonds) | | 88.9 |
| | 97.2 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 23.0 |
| | 26.2 |
| 27.6 |
| | 23.0 |
|
ANO Fukushima and Flood Barrier costs - recovered through retail rates through February 2026 (Note 2 - Retail Rate Proceedings) (b) | | 16.1 |
| | — |
|
MISO costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (b) | | 11.1 |
| | 17.5 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined annually | 18.1 |
| | 23.3 |
| 10.1 |
| | 18.1 |
|
MISO implementation costs - recovery through retail rates through 2018 (Note 2 - Retail Rate Proceedings) (c) | 17.5 |
| | 25.1 |
| |
Human capital management costs - recovery through retail rates through June 2017 (Note 2 - Retail Rate Proceedings) (c) | 10.4 |
| | 17.3 |
| |
Lake Catherine 4 reliability and sustainability cost deferral - recovery expected through retail rates (c)(b) | 10.4 |
| | 2.4 |
| 9.8 |
| | 10.4 |
|
Incremental ice storm costs - recovered through 2032 | 8.4 |
| | 9.0 |
| 7.9 |
| | 8.4 |
|
Human capital management costs - recovery through retail rates through June 2017 (Note 2 - Retail Rate Proceedings) (b) | | 7.0 |
| | 10.4 |
|
| Other | 8.6 |
| | 10.4 |
| 11.5 |
| | 8.6 |
|
| Entergy Arkansas Total |
| $1,333.8 |
| |
| $1,391.3 |
|
| $1,428.0 |
| |
| $1,333.8 |
|
Entergy Louisiana
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (a) |
| $715.7 |
| |
| $718.7 |
|
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (a) | 199.4 |
| | 180.8 |
|
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | 97.8 |
| | 119.2 |
|
New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (b) | 43.1 |
| | 50.4 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 27.0 |
| | 19.2 |
|
MISO costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 21.8 |
| | 41.1 |
|
Business combination external costs deferral - recovery through formula rate plan beginning December 2015 through November 2025 (b) | 15.2 |
| | 16.1 |
|
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | 14.8 |
| | 16.7 |
|
Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 10.0 |
| | 17.6 |
|
| Other | 23.3 |
| | 38.1 |
|
| Entergy Louisiana Total |
| $1,168.1 |
| |
| $1,217.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy LouisianaMississippi
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Non-Qualified Pension Plans) (b) |
| $718.7 |
| |
| $774.0 |
|
Asset Retirement Obligation - recovery dependent upon timing of decommissioning of nuclear units or dismantlement of non-nuclear power plants (Note 9) (b) | 180.8 |
| | 167.5 |
|
Little Gypsy costs – recovered through securitization (Note 5 – Entergy Louisiana Securitization Bonds - Little Gypsy) | 119.2 |
| | 139.2 |
|
New nuclear generation development costs - recovery through formula rate plan beginning December 2014 through November 2022 (Note 2 - New Nuclear Generation Development Costs) (c) | 50.4 |
| | 58.4 |
|
MISO implementation costs - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 26.6 |
| | 37.1 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 19.2 |
| | 21.1 |
|
Human capital management costs - recovery through formula rate plan beginning December 2014 through November 2017 (Note 2 - Retail Rate Proceedings) | 17.6 |
| | 25.0 |
|
River Bend AFUDC - recovered through August 2025 (Note 1 – River Bend AFUDC) | 16.7 |
| | 18.6 |
|
Business combination external costs deferral - recovery through formula rate plan beginning December 2015 through November 2025 (c) | 16.1 |
| | — |
|
MISO integration deferral - recovery through the MISO cost recovery mechanism beginning December 2014 through November 2017 | 14.5 |
| | 23.3 |
|
Gas hedging costs - recovered through fuel rates (Note 16 - Derivatives) | 7.0 |
| | 15.8 |
|
Spindletop gas storage facility - recovery period through August 2016 (a) (Note 2 - System Agreement Cost Equalization Proceedings) | 1.1 |
| | 26.2 |
|
| Other | 30.0 |
| | 34.4 |
|
| Entergy Louisiana Total |
| $1,217.9 |
| |
| $1,340.6 |
|
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $217.2 |
| |
| $216.1 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 82.0 |
| | 77.5 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 18.9 |
| | 7.1 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined annually | 9.3 |
| | 7.6 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 7.2 |
| | 6.7 |
|
| Other | 7.6 |
| | 13.7 |
|
| Entergy Mississippi Total |
| $342.2 |
| |
| $328.7 |
|
Entergy New Orleans
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $108.8 |
| |
| $103.7 |
|
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 93.6 |
| | 104.0 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 40.1 |
| | 29.4 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 4.3 |
| | 3.1 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 4.2 |
| | 4.0 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 3.4 |
| | 1.6 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 3.3 |
| | 5.2 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | 3.0 |
| | 3.2 |
|
| Other | 7.4 |
| | 11.1 |
|
| Entergy New Orleans Total |
| $268.1 |
| |
| $265.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) |
| $216.1 |
| |
| $224.3 |
|
Removal costs - recovered through depreciation rates (Note 9) (b) | 77.5 |
| | 76.3 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined annually | 7.6 |
| | 27.0 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 7.1 |
| | 8.2 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b) | 6.7 |
| | 6.3 |
|
Baxter Wilson outage costs - recovered through retail rates over two years beginning February 2015 (Note 8 - Baxter Wilson Plant Event) | 3.2 |
| | 6.0 |
|
MISO implementation costs - recovery through retail rate riders (Note 2 – Retail Rate Proceedings) | 2.7 |
| | 4.0 |
|
| Other | 7.8 |
| | 12.6 |
|
| Entergy Mississippi Total |
| $328.7 |
| |
| $364.7 |
|
Entergy New Orleans
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) |
| $104.0 |
| |
| $18.5 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b) | 103.7 |
| | 115.8 |
|
Removal costs - recovered through depreciation rates (Note 9) (b) | 29.4 |
| | 35.2 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 5.2 |
| | 7.2 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (b) | 4.0 |
| | 3.8 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 3.1 |
| | 0.4 |
|
Rate case costs - recovered through retail rates (c) | 3.2 |
| | 3.0 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 1.6 |
| | 1.8 |
|
| Other | 11.1 |
| | 9.2 |
|
| Entergy New Orleans Total |
| $265.3 |
| |
| $194.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 2 - Storm Cost Recovery Filings with Retail Regulators) |
| $516.2 |
| |
| $591.7 |
| |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) | |
| $442.4 |
| |
| $516.2 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (b)(a) | 193.6 |
| | 217.0 |
| 201.7 |
| | 193.6 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 57.4 |
| | 66.2 |
| 47.9 |
| | 57.4 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 25.8 |
| | 18.9 |
| 33.5 |
| | 25.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 9.4 |
| | 10.5 |
| 9.0 |
| | 9.4 |
|
Rate case costs - recovered through retail rates (c)(b) | 3.8 |
| | 8.4 |
| 0.5 |
| | 3.8 |
|
| Other | 6.7 |
| | 9.4 |
| 5.2 |
| | 6.7 |
|
| Entergy Texas Total |
| $812.9 |
| |
| $922.1 |
|
| $740.2 |
| |
| $812.9 |
|
System Energy
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (b)(a) |
| $178.0 |
| |
| $191.0 |
|
| $193.5 |
| |
| $178.0 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (b)(a) | 108.6 |
| | 80.4 |
| 142.5 |
| | 108.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (b)(a) | 54.8 |
| | 55.7 |
| 69.7 |
| | 54.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 6.4 |
| | 8.5 |
| 5.5 |
| | 6.4 |
|
| System Energy Total |
| $347.8 |
| |
| $335.6 |
|
| $411.2 |
| |
| $347.8 |
|
| |
| (a) | The jurisdictional split order assigned the regulatory asset to Entergy Texas. The regulatory asset, however, is being recovered and amortized at Entergy 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 Louisiana and Entergy Louisiana has recorded a corresponding payable. |
| |
(b) | Does not earn a return on investment, but is offset by related liabilities. |
| |
(c)(b) | Does not earn a return on investment. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Regulatory Liabilities
Entergy
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $611.7 |
| |
| $656.7 |
| |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | |
| $735.5 |
| |
| $611.7 |
|
Vidalia purchased power agreement (Note 8) | 222.6 |
| | 242.8 |
| 202.4 |
| | 222.6 |
|
Louisiana Act 55 financing savings obligation (Note 2) | 156.0 |
| | 156.0 |
| |
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 105.2 |
| | — |
| 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | | 68.0 |
| | 31.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | | 67.9 |
| | 67.9 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 68.3 |
| | 82.7 |
| 53.9 |
| | 68.3 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 79.5 |
| |
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA | 46.4 |
| | 53.6 |
| |
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
| 44.4 |
| | 44.4 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 31.7 |
| | — |
| |
Asset retirement obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a) | 28.2 |
| | 27.7 |
| |
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | | 39.3 |
| | 46.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | | 32.7 |
| | 28.2 |
|
| Other | 32.5 |
| | 40.2 |
| 79.8 |
| | 32.5 |
|
| Entergy Total |
| $1,414.9 |
| |
| $1,383.6 |
|
| $1,572.9 |
| |
| $1,414.9 |
|
Entergy Arkansas
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $236.1 |
| |
| $254.0 |
| |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | |
| $280.8 |
| |
| $236.1 |
|
| Other | 6.8 |
| | — |
| 25.1 |
| | 6.8 |
|
| Entergy Arkansas Total |
| $242.9 |
| |
| $254.0 |
|
| $305.9 |
| |
| $242.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) | |
| $235.4 |
| |
| $196.9 |
|
Vidalia purchased power agreement (Note 8) |
| $222.6 |
| |
| $242.8 |
| 202.4 |
| | 222.6 |
|
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) | 196.9 |
| | 209.1 |
| |
Louisiana Act 55 financing savings obligation (Note 2) | 156.0 |
| | 156.0 |
| |
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 105.2 |
| | — |
| 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | | 68.0 |
| | 31.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 68.3 |
| | 82.6 |
| 53.9 |
| | 68.3 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 31.7 |
| | — |
| |
Asset Retirement Obligation - will be returned to customers dependent upon timing of decommissioning (Note 9) (a) | 28.2 |
| | 27.7 |
| |
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | | 32.7 |
| | 28.2 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | | 10.9 |
| | — |
|
| Other | 9.7 |
| | 4.2 |
| 28.7 |
| | 9.7 |
|
| Entergy Louisiana Total |
| $818.6 |
| |
| $722.4 |
|
| $881.0 |
| |
| $818.6 |
|
Entergy Texas
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $6.4 |
| |
| $5.1 |
|
| $6.2 |
| |
| $6.4 |
|
| Other | | 2.3 |
| | — |
|
| Entergy Texas Total |
| $6.4 |
| |
| $5.1 |
|
| $8.5 |
| |
| $6.4 |
|
System Energy
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $178.7 |
| |
| $193.6 |
|
| $219.3 |
| |
| $178.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 79.5 |
| 67.9 |
| | 67.9 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the UPSA | 46.4 |
| | 53.6 |
| |
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
| 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | | 39.3 |
| | 46.4 |
|
| System Energy Total |
| $337.4 |
| |
| $371.1 |
|
| $370.9 |
| |
| $337.4 |
|
| |
| (a) | Offset by related asset. |
Fuel and purchased power cost recovery
Entergy Arkansas, 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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
table below shows the amount of deferred fuel costs as of December 31, 20152016 and 20142015 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas (a) |
| $57.8 |
| |
| $209.2 |
|
| $163.6 |
| |
| $57.8 |
|
| Entergy Louisiana (b) |
| $102.9 |
| |
| $107.1 |
|
| $119.9 |
| |
| $102.9 |
|
| Entergy Mississippi |
| ($107.8 | ) | |
| ($2.2 | ) |
| $7.0 |
| |
| ($107.8 | ) |
| Entergy New Orleans (b) |
| ($24.9 | ) | |
| ($25.1 | ) |
| $8.9 |
| |
| ($24.9 | ) |
| Entergy Texas |
| ($25.1 | ) | |
| $11.9 |
|
| ($54.5 | ) | |
| ($25.1 | ) |
| |
| (a) | 2015Includes $66.9 million in 2016 and 2014 include respectively $66.7 million and $65.9 million for Entergy Arkansasin 2015 of fuel and 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 recovered over a period greater than twelve months. |
| |
| (b) | 2015 and 2014 includeIncludes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year 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 recovered 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.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update will continuecontinued through June 2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and rates will be effective through June 2017.
Energy Cost Recovery RiderEntergy New Orleans
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $108.8 |
| |
| $103.7 |
|
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 93.6 |
| | 104.0 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 40.1 |
| | 29.4 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 4.3 |
| | 3.1 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 4.2 |
| | 4.0 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 3.4 |
| | 1.6 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 3.3 |
| | 5.2 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | 3.0 |
| | 3.2 |
|
| Other | 7.4 |
| | 11.1 |
|
| Entergy New Orleans Total |
| $268.1 |
| |
| $265.3 |
|
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the prior calendar-year energy costs and projected energy sales for
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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- 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.
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 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 that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas 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 sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will 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 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. The testimony was filed, and the APSC will decide the case based on the record in the proceeding.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
Entergy LouisianaTexas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) |
| $442.4 |
| |
| $516.2 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | 201.7 |
| | 193.6 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 47.9 |
| | 57.4 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 33.5 |
| | 25.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 9.0 |
| | 9.4 |
|
Rate case costs - recovered through retail rates (b) | 0.5 |
| | 3.8 |
|
| Other | 5.2 |
| | 6.7 |
|
| Entergy Texas Total |
| $740.2 |
| |
| $812.9 |
|
Entergy Louisiana recovers 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 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.System Energy
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a) |
| $193.5 |
| |
| $178.0 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a) | 142.5 |
| | 108.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 69.7 |
| | 54.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 5.5 |
| | 6.4 |
|
| System Energy Total |
| $411.2 |
| |
| $347.8 |
|
| |
| (a) | Does not earn a return on investment, but is offset by related liabilities. |
| |
| (b) | Does not earn a return on investment. |
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
realign the recovery of approximately $1 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seeking further proceedings regarding certain issues it raised in its comments on the LPSC Staff report. Entergy Louisiana has filed responses to both the LPSC Staff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submitted in October 2013 by the parties. A status conference was held in December 2013. Discovery has ceased and the parties are awaiting issuance of the audit report of the LPSC staff, but a procedural schedule has not been established.Other Regulatory Liabilities
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 has ceased and the parties are awaiting issuance of the audit report of the LPSC staff, but a procedural schedule has not been established.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.
In July 2014 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 by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015. |
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $735.5 |
| |
| $611.7 |
|
Vidalia purchased power agreement (Note 8) | 202.4 |
| | 222.6 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 68.0 |
| | 31.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 53.9 |
| | 68.3 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 39.3 |
| | 46.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 32.7 |
| | 28.2 |
|
| Other | 79.8 |
| | 32.5 |
|
| Entergy Total |
| $1,572.9 |
| |
| $1,414.9 |
|
Entergy MississippiArkansas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $280.8 |
| |
| $236.1 |
|
| Other | 25.1 |
| | 6.8 |
|
| Entergy Arkansas Total |
| $305.9 |
| |
| $242.9 |
|
Entergy Mississippi’s rate schedules include an energy cost recovery rider that 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.
Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi shall file a revised fuel factor with the MPSC no later than
Entergy Corporation and Subsidiaries
Notes to Financial Statements
February 1, 2016. In February 2016, Entergy Mississippi submitted a revised fuel factor reflecting a natural gas price of $2.45 per MMBtu.Louisiana
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $235.4 |
| |
| $196.9 |
|
Vidalia purchased power agreement (Note 8) | 202.4 |
| | 222.6 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 68.0 |
| | 31.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 53.9 |
| | 68.3 |
|
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 32.7 |
| | 28.2 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | 10.9 |
| | — |
|
| Other | 28.7 |
| | 9.7 |
|
| Entergy Louisiana Total |
| $881.0 |
| |
| $818.6 |
|
Mississippi Attorney General ComplaintEntergy Texas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $6.2 |
| |
| $6.4 |
|
| Other | 2.3 |
| | — |
|
| Entergy Texas Total |
| $8.5 |
| |
| $6.4 |
|
The Mississippi attorney general filed a complaint in state court in December 2008 against System Energy
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $219.3 |
| |
| $178.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 39.3 |
| | 46.4 |
|
| System Energy Total |
| $370.9 |
| |
| $337.4 |
|
| |
| (a) | Offset by related asset. |
Fuel and purchased power cost recovery
Entergy Corporation,Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy Services,New Orleans, and Entergy Power alleging, among other things, violations of Mississippi statutes, fraud,Texas are allowed to recover fuel and breach of good faithpurchased power costs through fuel mechanisms included in electric and fair dealing,gas rates that are recorded as fuel cost recovery revenues. The difference between revenues collected and requesting an accountingthe current fuel and restitution.purchased power costs is generally recorded as “Deferred fuel costs” on the Utility operating companies’ financial statements. 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 lawsuit 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
table below shows the amount of deferred fuel costs as of December 31, 2016 and 2015 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
| Entergy Arkansas (a) |
| $163.6 |
| |
| $57.8 |
|
| Entergy Louisiana (b) |
| $119.9 |
| |
| $102.9 |
|
| Entergy Mississippi |
| $7.0 |
| |
| ($107.8 | ) |
| Entergy New Orleans (b) |
| $8.9 |
| |
| ($24.9 | ) |
| Entergy Texas |
| ($54.5 | ) | |
| ($25.1 | ) |
| |
| (a) | Includes $66.9 million in 2016 and $66.7 million in 2015 of fuel and purchased power costs, which 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. |
| |
| (b) | Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year 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 recovered over a period greater than twelve months. |
Entergy Arkansas
Production Cost Allocation Rider
The defendant Entergy companies answered the complaint and filedAPSC approved a counterclaimproduction cost allocation rider 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 jurisdictionrecovery from customers of the MPSC, and factual errorsretail portion of the costs allocated to Entergy Arkansas as a result of the System Agreement proceedings, which are discussed in the Attorney General’s complaint. In September 2012“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 District Court heard oral argument on Entergy’s motion for judgment on the pleadings. costs over seven months but collects them from customers over twelve months.
In JanuaryMay 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the U.S. Supreme Court issuedAPSC suspended the annual redetermination of the production cost allocation rider and scheduled a decisionhearing in which it held that cases brought by attorneys general asSeptember 2014. Upon a joint motion of the sole plaintiff to enforce state laws were not considered “mass actions” underparties, the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day laterAPSC canceled the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction,September 2014 hearing and the District Court held oral argument on the renewed motion to remand in February 2014. In AprilJanuary 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth CircuitAPSC issued an order denyingapproving Entergy Arkansas’s request for recovery of the appeal,$3 million under-recovered amount based on the true-up of the production cost allocation rider and the Attorney General subsequently filed a petition for rehearing$67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the requestproduction cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for interlocutory appeal,calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which was also denied. The case remains pendingreflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in federal district court, awaitingthe amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a ruling on$1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the Entergy companies’ motion for judgment on the pleadings. InFERC’s December 2015 order related to test year 2009 production costs. The rates for the District Court ordered that2016 production cost allocation rider update became effective with the parties submit to the court undisputedfirst billing cycle of July 2016, and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.rates will be effective through June 2017.
Entergy New Orleans
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) |
| $108.8 |
| |
| $103.7 |
|
Storm damage costs, including hurricane costs - recovered through retail rates and securitization (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 93.6 |
| | 104.0 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 40.1 |
| | 29.4 |
|
Retail rate deferrals - recovered through rate riders as rates are redetermined monthly or annually | 4.3 |
| | 3.1 |
|
Asset retirement obligation - recovery dependent upon timing of dismantlement of non-nuclear power plants (Note 9) (a) | 4.2 |
| | 4.0 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 3.4 |
| | 1.6 |
|
Michoud plant maintenance – recovered over a 7-year period through September 2018 | 3.3 |
| | 5.2 |
|
Rate case costs - recovered over a 6-year period through September 2021 (Note 2 - Retail Rate Proceedings) | 3.0 |
| | 3.2 |
|
| Other | 7.4 |
| | 11.1 |
|
| Entergy New Orleans Total |
| $268.1 |
| |
| $265.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Texas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Storm damage costs, including hurricane costs - recovered through securitization and retail rates (Note 5 - Entergy Texas Securitization Bonds) |
| $442.4 |
| |
| $516.2 |
|
Pension & postretirement costs (Note 11 – Qualified Pension Plans, Other Postretirement Benefits, and Non-Qualified Pension Plans) (a) | 201.7 |
| | 193.6 |
|
Transition to competition costs - recovered over a 15-year period through February 2021 | 47.9 |
| | 57.4 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 33.5 |
| | 25.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 9.0 |
| | 9.4 |
|
Rate case costs - recovered through retail rates (b) | 0.5 |
| | 3.8 |
|
| Other | 5.2 |
| | 6.7 |
|
| Entergy Texas Total |
| $740.2 |
| |
| $812.9 |
|
System Energy
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Pension & postretirement costs (Note 11 – Qualified Pension Plans and Other Postretirement Benefits) (a) |
| $193.5 |
| |
| $178.0 |
|
Asset retirement obligation - recovery dependent upon timing of decommissioning (Note 9) (a) | 142.5 |
| | 108.6 |
|
Removal costs - recovered through depreciation rates (Note 9) (a) | 69.7 |
| | 54.8 |
|
Unamortized loss on reacquired debt - recovered over term of debt | 5.5 |
| | 6.4 |
|
| System Energy Total |
| $411.2 |
| |
| $347.8 |
|
| |
| (a) | Does not earn a return on investment, but is offset by related liabilities. |
| |
| (b) | Does not earn a return on investment. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Regulatory Liabilities
Entergy
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $735.5 |
| |
| $611.7 |
|
Vidalia purchased power agreement (Note 8) | 202.4 |
| | 222.6 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 68.0 |
| | 31.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 53.9 |
| | 68.3 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 39.3 |
| | 46.4 |
|
Asset retirement obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 32.7 |
| | 28.2 |
|
| Other | 79.8 |
| | 32.5 |
|
| Entergy Total |
| $1,572.9 |
| |
| $1,414.9 |
|
Entergy Arkansas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $280.8 |
| |
| $236.1 |
|
| Other | 25.1 |
| | 6.8 |
|
| Entergy Arkansas Total |
| $305.9 |
| |
| $242.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 16) (a) |
| $235.4 |
| |
| $196.9 |
|
Vidalia purchased power agreement (Note 8) | 202.4 |
| | 222.6 |
|
Louisiana Act 55 financing savings obligation (Note 2 - Storm Cost Recovery Filings with Retail Regulators) | 165.5 |
| | 156.0 |
|
Business combination guaranteed customer benefits - returned to customers through retail rates and fuel rates beginning December 2015 through November 2024 (Note 2 - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination) | 83.5 |
| | 105.2 |
|
Waterford 3 replacement steam generator provision (Note 2 - Retail Rate Proceedings) | 68.0 |
| | 31.7 |
|
Removal costs - returned to customers through depreciation rates (Note 9) (a) | 53.9 |
| | 68.3 |
|
Asset Retirement Obligation - return to customers dependent upon timing of decommissioning (Note 9) (a) | 32.7 |
| | 28.2 |
|
Gas hedging costs - refunded through fuel rates (Note 15 - Derivatives) | 10.9 |
| | — |
|
| Other | 28.7 |
| | 9.7 |
|
| Entergy Louisiana Total |
| $881.0 |
| |
| $818.6 |
|
Entergy Texas
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Transition to competition costs - returned to customers through rate riders when rates are redetermined periodically |
| $6.2 |
| |
| $6.4 |
|
| Other | 2.3 |
| | — |
|
| Entergy Texas Total |
| $8.5 |
| |
| $6.4 |
|
System Energy
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
Unrealized gains on nuclear decommissioning trust funds (Note 17) (a) |
| $219.3 |
| |
| $178.7 |
|
Grand Gulf sale-leaseback - (Note 10 - Sale and Leaseback Transactions) | 67.9 |
| | 67.9 |
|
Entergy Arkansas’s accumulated accelerated Grand Gulf amortization - will be returned to customers when approved by the APSC and FERC | 44.4 |
| | 44.4 |
|
Entergy Mississippi’s accumulated accelerated Grand Gulf amortization - amortized and credited through the Unit Power Sales Agreement | 39.3 |
| | 46.4 |
|
| System Energy Total |
| $370.9 |
| |
| $337.4 |
|
| |
| (a) | Offset by related asset. |
Fuel and purchased power cost recovery
Entergy Arkansas, 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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
table below shows the amount of deferred fuel costs as of December 31, 2016 and 2015 that Entergy expects to recover (or return to customers) through fuel mechanisms, subject to subsequent regulatory review.
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
| Entergy Arkansas (a) |
| $163.6 |
| |
| $57.8 |
|
| Entergy Louisiana (b) |
| $119.9 |
| |
| $102.9 |
|
| Entergy Mississippi |
| $7.0 |
| |
| ($107.8 | ) |
| Entergy New Orleans (b) |
| $8.9 |
| |
| ($24.9 | ) |
| Entergy Texas |
| ($54.5 | ) | |
| ($25.1 | ) |
| |
| (a) | Includes $66.9 million in 2016 and $66.7 million in 2015 of fuel and purchased power costs, which 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. |
| |
| (b) | Includes $168.1 million in each year for Entergy Louisiana and $4.1 million in each year 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 recovered 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.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September 2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update continued through June 2016.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and rates will be effective through June 2017.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the 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- 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.
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 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 that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas 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 sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will 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 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. The testimony was filed, and the APSC will decide the case based on the record in the proceeding.
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section in Note 8 to the financial statements for further discussion of the ANO stator incident.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Louisiana
Entergy Louisiana recovers 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 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 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 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor sought further proceedings regarding certain issues it raised in its comments on the LPSC staff report. Entergy Louisiana filed responses to both the LPSC staff report and the issues raised by the intervenor. After conducting additional discovery, in April 2016 the LPSC staff consultant issued its supplemental audit report, which concluded that Entergy Louisiana was not imprudent on the issues raised by the intervenor. The intervenor has stated that it does not intend to pursue these issues further. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue is outstanding in the Entergy Gulf States Louisiana audit for the same time period. In November 2016 the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. A procedural schedule has been established for this new docket, including an evidentiary hearing in June 2017.
In December 2011 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 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. In March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that is was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a settlement, which was approved by the LPSC in November 2016. The settlement recognizes the dry cask storage recovery method issue will be addressed in the separate proceeding opened by the LPSC, and provides for a refund of $5 million to legacy Entergy Gulf States Louisiana customers and resolves all other issues raised in the audit.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.
In July 2014 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 by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.
In June 2016 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges
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flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery has not commenced.
Entergy Mississippi
Entergy Mississippi’s rate schedules include an energy cost recovery rider that 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.
Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi shall file a revised fuel factor with the MPSC no later than February 1, 2016. Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor effective April 2016 to flow through to customers the projected over-recovery balance over a six-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.
In November 2016, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016.
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
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defendant Entergy companies removed the Attorney General’s lawsuit 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.
In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.
In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings, and the parties are in the process of preparing a proposed case management order.
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.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
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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
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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 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. Entergy Texas completed this refund to customers in March 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 August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The federal appeal was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. The State District Court appeal remains pending. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund.
In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also is requesting a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 transmission cost recovery factor rider amendment discussed below, and the terms and conditions in both settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.
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At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Retail Rate Proceedings
Filings with the APSC (Entergy Arkansas)
Retail Rates
2013 Base Rate Filing
In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million,
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including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allowed Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also ordered Entergy Arkansas to file a detailed report of the Arkansas-specific costs, savings and final payroll changes upon conclusion of the human capital management strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report was addressed in Entergy Arkansas’s 2015 base rate filing.period. New rates under the January 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates were effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.
2015 Base Rate Filing
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In MaySeptember 2015 the APSC issued an order suspending the proposed rates and tariffs filed by Entergy Arkansas and establishing a procedural schedule to complete its investigation of Entergy Arkansas’s application. In September 2015, APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. Entergy Arkansas filed rebuttal testimony in October 2015. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposesproposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity.
A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that would reducereduced the retail rate increase proposed in the settlement by $5 million. The settling parties were directedagreed to inform the APSC by filing no later thanmodifications in February 26, 2016 whether they accept the APSC’s proposed settlement agreement modification or request a full hearing on the issues. Entergy Arkansas plans to make its first formula rate plan filing in July 2016 for2016. The new rates were effective with the first billing cycle of January 2017.
A significant portion of the rate increase is related to Entergy Arkansas’s acquisition of Union Power Station Power Block 2 for an expected base purchase price of $237 million, subject to adjustment. The acquisition is expected to be completed promptly following the receipt of FERC approval. If the acquisition closes on or before MarchFebruary 24, 2016 recovery of the costs to acquire Power Block 2 of the Union Power Station will be through Entergy Arkansas’s new base rates that will commenceand began billing with the first billing cycle of April 2016. IfIn March 2016, Entergy Arkansas made a compliance filing regarding the transaction closes afternew rates that date,included an interim base rate adjustment surcharge, effective with the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.first billing cycle of April 2016,
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to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
2016 Formula Rate Plan Filing
In July 2016, Entergy Arkansas filed with the APSC its 2016 formula rate plan filing showing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. The APSC indicated that a procedural schedule would be set by subsequent order to obtain the additional information. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017.
Advanced Metering Infrastructure (AMI) Filing
In September 2016, Entergy Arkansas filed an application seeking an order from the APSC finding that Entergy Arkansas’s deployment of AMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Arkansas’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $431 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $57 million, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the APSC, deployment of the communications network is expected to begin in 2018. Entergy Arkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings. In order to have certainty around its 2018 projected AMI deployment costs, Entergy Arkansas sought an order from the APSC prior to the hearing on its expected 2017 formula rate plan filing in the fourth quarter 2017. In January 2017 the APSC approved a procedural schedule that provides for a hearing in August 2017.
Filings with the LPSC (Entergy Louisiana)
Retail Rates - Electric
2013 Rate Cases
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 in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:
authorization to increase the revenue it collects from customers by approximately $24 million;
an authorized return on common equity of 10.4%;
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authorization to increase depreciation rates embedded in the proposed revenue requirement; and,
authorization to implement a three-year formula rate planplan: 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.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates willdid not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings arewere subject to LPSC review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.
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 resulted in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for the incremental capacity rider. In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity
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of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicated 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. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected 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. In April 2013, Entergy Louisiana and the LPSC staff filed a joint report resolving the 2011 test year formula rate plan and recovery related to the Grand Gulf uprate. This report was approved by the LPSC in April 2013.
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. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:
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 planplan: 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.
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Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provided for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates willdid not change.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to
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be collected over nine months was implemented in December 2014. The compliance filings arewere subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. Additionally, the adjustments of rates made related to the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project. LPSC staff identified five issues, of which two remain. The remaining issues pertainone remains in the compliance proceeding. That issue pertains to Entergy Louisiana’s method of collecting the agreed-upon $10 million increase and the level of recovery of investment related to the Grand Gulf uprate.increase. No procedural schedule has been established, however, to address these remaining issues. Thethe issue. By stipulation among the parties, the final issue raised by the LPSC staff pertains toregarding the appropriate level of refunds related to the Waterford 3 replacement steam generator project. That issueproject will be resolved in connection with the Waterford 3 prudence review proceedings discussed below.
2014 Formula Rate Plan Filing
In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflects an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue is required. The following other adjustments, however, are required under the formula rate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented with the first billing cycle of September 2016, subject to refund. Following implementation of the as-filed rates in September 2016, there have been several interim updates to Entergy Louisiana’s formula rate plan, including the most recent adjustment submitted in December 2016, reflecting implementation of the settlement of the Waterford 3 replacement steam generator project prudence review described below. Also pursuant to Entergy Louisiana’s formula rate plan rider, in November 2016, Entergy Louisiana submitted a request for LPSC authorization to extend the recovery mechanism for net revenues and expenses incurred in connection with Entergy Louisiana’s participation in MISO. The MISO cost recovery mechanism was initially approved on an interim basis to remain in place through the rate effective period of Entergy Louisiana’s test year 2015 formula rate plan filing. A procedural schedule has been established, including a hearing in July 2017.
Waterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 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 2014 the LPSC Staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believesbelieved that the replacement steam generator costs were prudently incurred and applicable legal principles supportsupported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation hashad not yet to bebeen considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project iswas no longer probable of recovery. Entergy Louisiana maintainsmaintained that the ALJ’s recommendation contains significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. This settlement was approved by the LPSC in December 2016. The settlement effectively provides for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The settlement also requires a refund of approximately $71 million to be given through a one-time credit included in customers’ bills in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues recorded through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provides that Entergy Louisiana can retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC.approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. A hearingTestimony filed by the LPSC staff generally supports the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is scheduledeligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in March 2016.January 2017.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Union Power Station
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
Business Combination
In connection with the approval of the business combination of Entergy Gulf States Louisiana andMarch 2016, Entergy Louisiana the LPSC authorized the filingacquired Power Blocks 3 and 4 of a single, joint formula rate plan evaluation reportUnion Power Station for Entergy Gulf States Louisiana’san aggregate purchase price of approximately $474 million and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue is required. The following adjustments are required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism,implemented rates to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implementedestimated first-year revenue requirement with the first billing cycle of December 2015, subjectMarch 2016.
As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to refund. In November 2015,make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, filed objections, corrections, and comments identifying several issuesintervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for potential rate adjustments, including: preservation of previously-raised issues;these four units in addition to information on the implementationcurrent deactivation decisions for the ten-year planning horizon. Parties have requested further proceedings on the prudence of the $10 million increase in annual formula rate plan revenue over abbreviated rate-effective period;decision to deactivate Willow Glen 2 and 4. No party contests the levelprudence of adjustmentthe decision to rates for the extended power uprate at System Energy, as well as asserting a general reservationdeactivate Willow Glen 2 and 4 or suggests reactivation of rights for further review of adjustmentsthese units; however, issues have been raised related to Ninemile 6 and the Waterford 3 provision for rate refund; change to gross plant, depreciation, and net plant components of rate base; regulatory debits and credits; adjustment for business combination expenses and the implementation of certain guaranteed customer credits. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” below for further discussion of the business combination.Louisiana’s deactivation process. This matter is pending before an ALJ.
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. In March 2013 the LPSC staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC staff reached agreement regarding the LPSC staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.
In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal
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Notes to Financial Statements
for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that does not affect current year results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. Absent approval of an extension byIn March 2016 the LPSC test yearstaff issued its report stating that the 2015 is the final year under the current gas rate stabilization plan.plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicates no outstanding issues remained in the filing. In February 2016, however, Entergy Louisiana filed a motion requesting to extend the termsterm of the gas rate stabilization plan in substantially similar form for an additional three-year term.term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC Staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.
In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflects an earned return on common equity of 6.37%. As part of the filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana is seeking to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana seeks to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing seeks an annual increase in revenue of $1.4 million. The filing is subject to review by the LPSC staff with resulting rates to be implemented with the first billing cycle of May 2017.
Advanced Metering Infrastructure (AMI) Filing
In November 2016, Entergy Louisiana filed an application seeking a finding from the LPSC that Entergy Louisiana’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable
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Notes to Financial Statements
network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $92 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Assuming LPSC approval is received in 2017, the communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022.
Filings with the MPSC (Entergy Mississippi)
Formula Rate Plan Filings
In March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills. Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.
In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management
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rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:
an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;
revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
recovery of non-fuel MISO-related costs through a separate rider for that purpose;
a deferral of $6 million in other operation and maintenance expenses associated with the unplanned Baxter Wilson outage in September 2013, and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See Note 8The final accounting of costs to return the financial statements for further discussionunit to service and insurance proceeds were to be addressed in Entergy Mississippi’s next formula rate plan filing. Subsequently, the MPSC ordered final review of the Baxter Wilson outage;accounting be completed in a separate docket; and
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs - Entergy
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Mississippi” below for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.
In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.
In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.
Advanced Metering Infrastructure (AMI) Filing
In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15 year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $56 million, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable.
Filings with the City Council
(Entergy Louisiana and Entergy New Orleans)
In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014 the City Council Advisors filed direct testimony recommending a rate increase of $5.56$5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
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The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the City Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area. See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.
(Entergy New Orleans)
Formula Rate PlanRetail Rates
In April 2009 the City Council approved a 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 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 also requested to increase annual funding for its storm reserve by approximately $5.7 million for 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. In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding. Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates. Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012. Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended.
See “Algiers Asset Transfer ” below for discussion of the Algiers asset transfer. As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for its operations in the Algiers area and certain exceptional cost increases or decreases in itsthe base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of thefrom Ninemile Unit 6 generating station (Ninemile PPA), which
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Notes to Financial Statements
commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisitionpurchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the special Ninemile 6terms of the purchased power and capacity acquisition cost recovery rider discussed above, to coverrecover the non-fuel purchased power expense from Ninemile 6, as well as the revenue requirement associated with the acquisitionpurchase of Union Power Block 1 upon closing of the transaction.Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
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. In October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans
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will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programsprogram from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In February 2017, Entergy New Orleans filed a proposed implementation plan for the Energy Smart program from April 2017 through March 2020. As part of the proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the City Council and the FERC. In the application, Entergy New Orleans had proposed to credit retail customers $5 million in each of the years 2016 and 2017 if the City Council approved the application in 2016, and to credit retail customers $5 million in each of the years 2018, 2019, and 2020, if an application that is yet to be filed with the FERC is approved by December 31, 2018. When it became clear that City Council approval would not be obtained in 2016, Entergy New Orleans agreed in testimony that it would extend its proposal to credit customers if City Council approval was obtained in the first quarter 2017. Entergy New Orleans still expects that the restructuring can be consummated by December 31, 2017, if the necessary approvals are obtained. In February 2017 the procedural schedule was suspended to allow for settlement discussions. It is not anticipated that NRC approval will be required to engage in the proposed internal restructuring. In January 2017, Entergy Louisiana, through Entergy Corporation’s nuclear operations organization, Entergy Operations, Inc. made a filing, however, with the NRC notifying it of the internal restructuring.
It is currently contemplated that Entergy New Orleans would undertake a multi-step restructuring, which would include the following:
Entergy New Orleans would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans will allocate substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power will assume substantially all of the liabilities of Entergy New Orleans, in a transaction regarded as a merger under the TXBOC. Entergy New Orleans will remain in existence and hold the membership interests in Entergy New Orleans Power.
Entergy New Orleans will contribute the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.
Upon the completion of the restructuring, Entergy New Orleans, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy New Orleans. Entergy New Orleans may modify or supplement the steps to be taken to effectuate the restructuring.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Advanced Metering Infrastructure (AMI) Filing
In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31,2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a procedural schedule that provides for a hearing in July 2017.
Filings with the PUCT and Texas Cities (Entergy Texas)
Retail Rates
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 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 measurable; reduced Entergy Texas’s regulatory assets associated with Hurricane Rita; excluded from rate recovery capitalized financially-based incentive compensation; included $1.6
Entergy Corporation and Subsidiaries
Notes to Financial Statements
million of MISO transition expense in base rates, and reduced Entergy’s Texas’s fuel reconciliation recovery by $4 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 also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Briefs were filed by the appealing and responding parties in the first half of 2015. Oral argument before the court panel was held in September 2015. TheIn April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. That petition is currently pending.
2013 Rate Case
In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, provides for recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.
2015 Rate Case
In June 2015, Entergy Texas filed a rate case that included pro forma adjustments to reflect the proposed acquisition of Union Power Station Power Block 1, which is one of four units that comprise the Union Power Station near El Dorado, Arkansas. Previously in 2015 Entergy Texas made a filing with the PUCT requesting that it grant a certificate of convenience and necessity for the Union acquisition. In July 2015 the PUCT requested briefing on legal and policy issues related to, among other things, the propriety of rate recovery for the Union Power transaction given the uncertainty of the actual closing date of the transaction and the commencement of the rate year, as well as Entergy Texas’s requirement for acceptable rate treatment as a condition to closing the transaction. Also in July 2015, in connection with the requested briefing, the PUCT staff and certain parties filed briefs concluding that Entergy Texas should not be permitted recovery for the Union Power Station purchase in the rate case. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the certificate of convenience and necessity filing and withdraw the rate case. In July 2015, Entergy Texas filed its notice of withdrawal
Entergy Corporation and Subsidiaries
Notes to Financial Statements
of its base rate case and the ALJs in the case dismissed the case from the dockets of the State Office of Administrative Hearings and the PUCT. In the third quarter 2015, Entergy Texas wrote off $4.7 million in rate case expenses and acquisition costs related to the proposed Union Power Station acquisition.
Other Filings
In September 2014, Entergy Texas filed for a distribution cost recovery factor (DCRF) rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent. In September 2015, Entergy Texas filed to amend its distribution cost recovery factor rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015, Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.
In September 2015, Entergy Texas filed for a transmission cost recovery factor (TCRF) rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase. The largest remaining single disallowance isincrease by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million which would impose ato account for load growth adjustment on Entergy Texas’s TCRF rider.since base rates were last set. A hearing on the merits was held in December 2015. AIn February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending
Entergy Corporation and Subsidiaries
Notes to Financial Statements
that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In April 2016 the PUCT voted to allow Entergy Texas’s TCRF rates to become effective as of April 14, 2016 when those rates are finally approved, but did not otherwise address the proposal for decision. In May 2016 the PUCT deferred final consideration of Entergy Texas’s TCRF application and opened the record to consider additional evidence to be provided by Entergy Texas and potentially other parties regarding the rate-making treatment of spare transmission-level transformers that are transferred among the Utility operating companies. In June 2016 the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.
In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is expected in first quarter 2016.designed to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently authorized to collect through the TCRF rider, as discussed above. In September 2016 the PUCT suspended the effective date of the tariff change to March 2017. In December 2016, concurrent with the 2016 fuel reconciliation stipulation and settlement agreement discussed above, Entergy Texas and the PUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. As discussed above, the terms of the two settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism
Entergy Corporation and Subsidiaries
Notes to Financial Statements
that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel tracker would reallocate such cost shifts as between legacy customers of the companies
Entergy Corporation and Subsidiaries
Notes to Financial Statements
on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs were recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.
In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. See Note 3 to the financial statements for further discussion of the customer credits resulting from the business combination.
Algiers Asset Transfer (Entergy Louisiana and Entergy New Orleans)
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million, subject to closing adjustments.million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million. See Note 1 to the financial statements for a discussion of the accounting for the Algiers asset transfer and the basis of presentation for the Entergy New Orleans’s financial statements presented in this report.
System Agreement Cost Equalization Proceedings
ThePrior to the termination of the System 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. Entergy Arkansas terminated its participation in the System Agreement which is a rate schedule thatin December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement terminated with respect to its remaining participants in August 2016.
Although the System Agreement has been approved by the FERC. Certainterminated, certain of the Utility operating companies’ retail regulators and other parties are pursuing litigation involving the System Agreement at the FERC.FERC and in federal courts. 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.other matters.
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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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.
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.
The financial consequences of the FERC’s decision are determined by the total production cost of each Utility operating company, which are affected by 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 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 generally increased the amount by which Entergy Arkansas’s total production costs were 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 March 2015, in light of the December 2014 decision by the D.C. Circuit in the interruptible load proceeding, Entergy filed with the FERC a motion to establish briefing schedule on refund issues and an initial brief addressing refund issues. The initial brief argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in this proceeding. In October 2015 the FERC issued three orders related to the commencement of the remedy on June 1, 2005 and the inclusion of interest on the amount for the period June 1, 2005 through December 31, 2005. Specifically, the FERC rejected Entergy Services’s request for rehearing of its decision to include interest on the amount for the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
seven-month period. The FERC also rejected Entergy Services’s request for rehearing of the order rejecting the compliance filing with regard to the issue of interest. Finally, the FERC set for hearing and settlement procedures the 2014 compliance filing that included the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005. In setting the compliance filing for hearing, the FERC rejected the APSC’s protest that Entergy Arkansas should not be subject to the filing because Entergy Arkansas would be making the payments during a period following its exit from the System Agreement. The hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 is scheduled to occuroccurred in July 2016. The presiding judge issued an initial decision in November 2016. In the initial decision, the presiding judge agreed with the Utility operating companies’ position that: (1) interest on the bandwidth payments for the 2005 test period shall be accrued from June 1, 2006 until the date that the bandwidth payments for that calculation are paid consistent with how the Utility operating companies performed the calculation; and (2) a portion of Entergy Louisiana’s 2001-vintage Louisiana state net operating loss accumulated deferred income tax that results from the Vidalia tax deduction should be excluded from the 2005 test period bandwidth calculation.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Various participants filed briefs on exceptions and/or briefs opposing exceptions related to the initial decision, including the LPSC, the APSC, the FERC trial staff, and Entergy Services. The initial decision is pending before the FERC.
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 (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $156 |
| Entergy Louisiana | ($75) |
| Entergy Mississippi | ($33) |
| Entergy New Orleans | ($5) |
| Entergy Texas | ($43) |
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. In December 2013 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the D.C. Circuit. In its petition, the LPSC requested that the D.C. Circuit issue an order compelling the FERC to issue a final order on pending rehearing requests. In January 2014 the D.C. Circuit denied the LPSC’s petition. 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 February 2014 the FERC issued a rehearing order addressing its October 2011 order. The FERC denied the LPSC’s request for rehearing on the issues of whether the bandwidth remedy should be made effective earlier than June 1, 2005, and whether refunds should be ordered for the 20-month refund effective period. The FERC granted the LPSC’s rehearing request on the issue of interest on the bandwidth payments/receipts for the June - December 2005 period, requiring that interest be accrued from June 1, 2006 until the date those bandwidth payments/receipts are made. Also in February 2014 the FERC issued an order rejecting the December 2011 compliance filing that calculated the bandwidth payments/receipts for the June - December 2005 period. The FERC order required a new compliance filing that calculates the bandwidth payments/receipts for the June - December 2005 period based on monthly data for the seven individual months including interest pursuant to the February 2014 rehearing order. Entergy has sought rehearing of the February 2014 orders with respect to the FERC’s determinations regarding interest. In April 2014 the LPSC filed a petition for review of the FERC’s October 2011 and February 2014 orders with the U.S. Court of Appeals for the D.C. Circuit. The appeal is pending.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In April and May 2014, Entergy filed with the FERC an updated compliance filing that provides the payments and receipts among the Utility operating companies pursuant to the FERC’s February 2014 orders. The filing shows the following net payments and receipts, including interest, among the Utility operating companies:
|
| |
| | Payments (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $68 |
| Entergy Louisiana | ($10) |
| Entergy Mississippi | ($11) |
| Entergy New Orleans | $2 |
| Entergy Texas | ($49) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
These payments were made in May 2014. The LPSC, City Council, and APSC have filed protests. As discussed above, the hearing on the bandwidth calculation for the seven months June 1, 2005 through December 31, 2005 occurred in July 2016.
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:
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Payments (Receipts) |
| | 2007 | | 2008 | | 2009 | | 2010 | | 2011 | | 2012 | | 2013 | | 2014 |
| | (In Millions) | | |
| Entergy Arkansas |
| $252 |
| |
| $252 |
| |
| $390 |
| |
| $41 |
| |
| $77 |
| |
| $41 |
| |
| $— |
| |
| $— |
|
| Entergy Louisiana |
| ($211 | ) | |
| ($160 | ) | |
| ($247 | ) | |
| ($22 | ) | |
| ($12 | ) | |
| ($41 | ) | |
| $— |
| |
| $— |
|
| Entergy Mississippi |
| ($41 | ) | |
| ($20 | ) | |
| ($24 | ) | |
| ($19 | ) | |
| ($40 | ) | |
| $— |
| |
| $— |
| |
| $— |
|
| Entergy New Orleans |
| $— |
| |
| ($7 | ) | |
| $— |
| |
| $— |
| |
| ($25 | ) | |
| $— |
| |
| ($15 | ) | |
| ($15 | ) |
| Entergy Texas |
| ($30 | ) | |
| ($65 | ) | |
| ($119 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $15 |
| |
| $15 |
|
The Utility operating companies record, as necessary, accounts payable or accounts receivable to reflect the rough production cost equalization payments and receipts required to implement the FERC’s remedy. When accounts payable are recorded, a corresponding regulatory asset is recorded for the right to collect the payments from customers. When accounts receivable are recorded, a corresponding regulatory liability is recorded for the obligations to pass the receipts on to customers. As discussed below, noNo payments and receipts were required in 2016 or 2015 to implement the FERC’s remedy based on calendar year 2015 production costs and 2014 production costs.costs, respectively. Entergy Arkansas ceased participating in the System Agreement on December 18, 2013 and was not part of the calendar year 2013 or 2014 production costs calculations. The System Agreement terminated in August 2016.
The APSC has approved a production cost allocation rider for recovery from customers of the retail portion of the costs allocated to Entergy Arkansas. Entergy Texas is recovering its 2013 rough production cost equalization payment over three years beginning April 2014. Entergy Texas included its 2014 rough production cost equalization payment as a component of an interim fuel refund made in 2014. 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Comprehensive Bandwidth Recalculation for 2007, 2008, and 2009 Rate Filing Proceedings
In July 2014 the FERC issued four orders in connection with various Service Schedule MSS-3 rough production cost equalization formula compliance filings and rehearing requests. Specifically, the FERC accepted Entergy Services’ revised methodologies for calculating certain cost components of the formula and affirmed its prior ruling requiring interest on the true-up amounts. The FERC directed that a comprehensive recalculation of the formula be performed for the filing years 2007, 2008, and 2009 based on calendar years 2006, 2007, and 2008 production costs. In September 2014, Entergy filed with the FERC its compliance filing that provides the payments and receipts, including interest, among the Utility operating companies pursuant to the FERC’s orders for the 2007, 2008, and 2009 rate filing proceedings. The filing shows the following additional payments/receipts among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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| |
| | Payments (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $38 |
| Entergy Louisiana | ($38) |
| Entergy Mississippi | $16 |
| Entergy New Orleans | ($1) |
| Entergy Texas | ($15) |
Entergy Arkansas and Entergy Mississippi made the payments in September and October 2014.
The FERC proceedings that resulted from rate filings made in 2007, 2008, and 2009 have been resolved by various orders issued by the FERC and appellate courts. See below for a discussion of rate filings since 2009 and the comprehensive recalculation filing directed by the FERC in the proceeding related to the 2010 rate filing.
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 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. In October 2013 the FERC issued an order granting clarification and denying rehearing with respect to its October 2011 rehearing order in this proceeding. The FERC clarified that in a bandwidth proceeding parties can challenge erroneous inputs, implementation errors, or prudence of cost inputs, but challenges to the bandwidth formula itself must be raised in a Federal Power Act section 206 complaint or section 205 filing. Subsequently in October 2013 the presiding ALJ lifted the stay order holding in abeyance the hearing previously ordered by the FERC and directing that the remaining issues proceed to a hearing on the merits. The hearing was held in March 2014 and the presiding ALJ issued an initial decision in September 2014. Briefs on exception were filed in October 2014. In December 2015 the FERC issued an order affirming the initial decision in part and rejecting the initial decision in part. Among other things, the December 2015 order directs Entergy Services to submit a compliance filing, the results of which may affect the rough production cost equalization filings made for the June - December 2005, 2006, 2007, and 2008 test periods. In January 2016 the LPSC, the APSC, and Entergy Services filed requests for rehearing of the FERC’s December 2015 order. In February 2016, Entergy Services submitted the compliance filing ordered in the December 2015 order. The result of the true-up payments and receipts for the recalculation of production costs resulted in the following payments/receipts among the Utility operating companies:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| |
| | Payments (Receipts) |
| | (In Millions) |
| Entergy Arkansas | $2 |
| Entergy Louisiana | $6 |
| Entergy Mississippi | ($4) |
| Entergy New Orleans | ($1) |
| Entergy Texas | ($3) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In September 2016 the FERC accepted the February 2016 compliance filing subject to a further compliance filing made in November 2016. The further compliance filing is required as a result of an order also issued in September 2016 ruling on the January 2016 rehearing requests filed by the LPSC, the APSC, and Entergy Services. In the order addressing the rehearing requests, the FERC granted the LPSC’s rehearing request and directed that interest be calculated on the payment/receipt amounts based on the 2009 production costs. The FERC also granted the APSC’s and Entergy Services’s rehearing request and ordered the removal of both securitized asset accumulated deferred income taxes and contra-securitization accumulated deferred income taxes from the calculation. In November 2016, Entergy Services submitted its compliance filing in response to the FERC’s order on rehearing. The compliance filing included a revised refund calculation of the true-up payments and receipts based on 2009 test year data and interest calculations. The LPSC protested the interest calculations and the compliance filing is pending an order from the FERC.
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 also filed a protest. 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. In January 2014 the LPSC filed a petition for a writ of mandamus at the United States Court of Appeals for the Fifth Circuit. In its petition, the LPSC requested that the Fifth Circuit issue an order compelling the FERC to issue a final order in several proceedings related to the System Agreement, including the 2011 rate filing based on calendar year 2010 production costs and the 2012 and 2013 rate filings discussed below. In March 2014 the Fifth Circuit rejected the LPSC’s petition for a writ of mandamus. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2011 rate filing with the 2012, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.
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 also filed a protest. 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 the prior production cost proceedings currently before the FERC on review. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2012 rate filing with the 2011, 2013, and 2014 rate filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.
2013 Rate Filing Based on Calendar Year 2012 Production Costs
In May 2013, Entergy filed with the FERC the 2013 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 also filed a protest. The City Council intervened and filed comments related to including the outcome of a related FERC proceeding in the 2013 cost equalization calculation. In August 2013 the FERC issued an order accepting the 2013 rates, effective June 1, 2013, 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. In December 2014 the FERC rescinded its earlier abeyance order and consolidated the 2013 Rate Filing with the 2011, 2012, and 2014 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
2014 Rate Filing Based on Calendar Year 2013 Production Costs
In May 2014, Entergy filed with the FERC the 2014 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 also
Entergy Corporation and Subsidiaries
Notes to Financial Statements
filed a protest. The City Council intervened and filed comments. In December 2014 the FERC issued an order accepting the 2014 rates, effective June 1, 2014, subject to refund, set the proceeding for hearing procedures, and consolidated the 2014 Rate Filing with the 2011, 2012, and 2013 Rate Filings for settlement and hearing procedures. See discussion below regarding the consolidated settlement and hearing procedures in connection with this proceeding.
Consolidated 2011, 2012, 2013, and 2014 Rate Filing Proceedings
As discussed above, in December 2014 the FERC consolidated the 2011, 2012, 2013, and 2014 rate filings for settlement and hearing procedures. In May 2015, Entergy filed direct testimony in the consolidated rate filings and the LPSC filed direct testimony concerning its complaint proceeding that is consolidated with the rate filings, challenging certain components of the pending bandwidth calculations for prior years. In July 2015 the parties filed direct and answering testimony. Among other issues with the pending bandwidth calculations, the LPSC challenged the administration of the accounting for joint account sales of energy in the intra-system bill. In August and September 2015 the parties filed additional rounds of testimony in the consolidated hearing for the 2011, 2012, 2013, and 2014 rate filings. In October 2015 the LPSC withdrew its testimony challenging the accounting for joint account sales of energy. The hearings occurred in November 2015, and an initial decision from the ALJ is expectedwas issued in July 2016.
2015 Rate Filing Based In the initial decision, the ALJ generally agreed with Entergy’s bandwidth calculations with one exception on Calendar Year 2014 Production Costs
In May 2015, Entergythe accounting related to the Waterford 3 sale/leaseback. Briefs were filed with the FERC the 2015 rates in accordance with the FERC’s orders in the System Agreement proceeding. The filing showed that no payments and receipts were required in 2015 to implement the FERC’s remedy based on calendar year 2014 production costs. Several parties intervened in the proceeding and the LPSC and City Council intervened and filed comments. In October 2015 the FERC accepted the 2015 rates for filing, suspended them for a nominal period, to become effective June 1, 2015, as requested, subject to refund, and set them for hearing and settlement judge procedures.
Calendar Year 2015 Production Costs
Entergy preliminarily estimates that no payments and receipts are required in 2016 to implement the FERC’s remedy based on calendar year 2015 production costs. The actual payments/receipts for 2016, based on calendar year 2015 production costs, will not be calculated until the Utility operating companies’ 2015 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. The calculation based on 2015 production costs will be the last rough production cost equalization filing submitted by the Utility operating companies because the System Agreement will terminate at the end of AugustSeptember 2016.
Utility Operating Company Termination of System Agreement Participation
Entergy Arkansas and Entergy Mississippi ceased participating in the System Agreement effective December 18, 2013 and November 7, 2015, respectively. Entergy Louisiana, Entergy New Orleans, and Entergy Texas will terminateterminated participation in the System Agreement on August 31, 2016, which will resultresulted in the termination of the System Agreement in its entirety pursuant to a settlement agreement approved by the FERC in December 2015.
In December 2013, the FERC set one issue for hearing involving whether and how the benefits associated with settlement with Union Pacific regarding certain coal delivery issues should be allocated among Entergy Arkansas and the other Utility operating companies post-termination of the System Agreement. In December 2014 a FERC ALJ issued an initial decision finding that Entergy Arkansas would realize benefits after December 18, 2013 from the 2008 settlement agreement between Entergy Services, Entergy Arkansas, and Union Pacific, related to certain coal delivery issues. The ALJ further found that all of the Utility operating companies should share in those benefits pursuant to the methodology proposed by the MPSC. The Utility operating companies and other parties to the proceeding filed briefs on exceptions and/or briefs opposing exceptions with the FERC challenging various aspects of the December 2014 initial decision. In March 2016 the FERC issued an opinion affirming the December 2014 initial decision with regard to the determination that there were benefits related to the Union Pacific settlement, which were realized post Entergy Arkansas’s December 2013 withdrawal from the System Agreement, that should be shared with the other Utility operating companies utilizing the methodology proposed by the MPSC and trued-up to actual coal volumes purchased. In May 2016, Entergy made a compliance filing that provided the calculation of Union Pacific settlement benefits utilizing the methodology adopted by the initial decision, trued-up for the actual volumes of coal purchased. The payments were made in May 2016. In August 2016 the FERC issued an order accepting Entergy’s compliance filing. Also in August 2016 the APSC filed a petition for review of the FERC’s March 2016 and August 2016 orders with the U.S. Court of Appeals for the D.C. Circuit.
In connection with the System Agreement termination settlement agreement, it was determined that the purchase power agreements, referred to as the jurisdictional separation plan PPAs, between Entergy Texas and Entergy Gulf States Louisiana that were put in place for certain legacy gas units at the time of Entergy Gulf States’s separation into Entergy Texas and Entergy Gulf States Louisiana will terminateterminated effective with the System Agreement termination. Similarly, the PPApurchase
Entergy Corporation and Subsidiaries
Notes to Financial Statements
power agreement between Entergy Gulf States Louisiana and Entergy Texas for the Calcasieu unit also will terminate. Currently,terminated. In March 2016, Entergy Services filed with the FERC the notices of termination. The jurisdictional separation plan PPAs arewere the means by which Entergy Texas receivesreceived payment for its receivable associated with Entergy Louisiana’s Spindletop gas storage facility regulatory asset. As a result of the
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Notes to Financial Statements
System Agreement termination settlement agreement, effective with the termination date, Entergy Texas will no longer receivereceives payments from Entergy Louisiana related to the Spindletop storage facility which resulted in a write-off recorded in 2015 by Entergy Texas of $23.5 million ($15.3 million net-of-tax). Upon termination of the System Agreement, other purchase power agreements entered into under Service Schedule MSS-4 of the System Agreement were replaced with updated agreements under a FERC-jurisdictional tariff effective September 1, 2016.
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.
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 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. In July 2011 the refunds made in the fourth quarter 2009 described above were reversed. In October 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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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
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Notes to Financial Statements
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.
In March 2013 the FERC issued an order denying the LPSC’s request for rehearing of the FERC’s June 2011 order wherein the FERC concluded it would exercise its discretion and not order refunds in the interruptible load proceeding. Based on its review of the LPSC’s request for rehearing and the briefs filed as part of the paper hearing established in October 2011, the FERC affirmed its earlier ruling and declined to order refunds under the circumstances of the case. In May 2013 the LPSC filed a petition for review with the U.S. Court of Appeals for the D.C. Circuit seeking review of FERC prior orders in the Interruptible Load Proceeding that concluded that the FERC would exercise its discretion and not order refunds in the proceeding. Oral argument was held on the appeal in the D.C. Circuit in September 2014. In December 2014 the D.C. Circuit issued an order on the LPSC’s appeal and remanded the case back to the FERC. The D.C. Circuit rejected the LPSC’s argument that there is a presumption in favor of refunds, but it held that the FERC had not adequately explained its decision to deny refunds and directed the FERC “to consider the relevant factors and weigh them against one another.” In March 2015, Entergy filed with the FERC a motion to establish a briefing schedule on remand and an initial brief on remand to address the December 2014 decision by the D.C. Circuit. The initial brief on remand argued that the FERC, in response to the D.C. Circuit decision, should clarify its policy on refunds and find that refunds are not required in the interruptible load proceeding.
In April 2016 the FERC issued an order on remand that addressed the December 2014 decision by the D.C. Circuit in the interruptible load proceeding. The matter is pending.order on remand affirmed the FERC’s denial of refunds for the 15-month refund effective period. The FERC explained and clarified its policies regarding refunds and concluded that the evidence in the record demonstrated that the relevant equitable factors favored not requiring refunds in this case. The FERC also noted that, under Section 206(c) of the Federal Power Act, in a Section 206 proceeding involving two or more electric utility companies of a registered holding company system, the FERC may order refunds only if it determines the refunds would not cause the registered holding company to experience any reduction in revenues resulting from an inability of an electric utility company in the system to recover the resulting increase in costs. The FERC stated it was not able to find that the Entergy system would not experience a reduction in revenues if refunds were awarded in this proceeding, which further supported the denial of refunds. In May 2016 the LPSC filed a request for rehearing of the FERC’s April 2016 order. In September 2016 the FERC issued an order denying the LPSC’s request for rehearing and reaffirming its denial of refunds for the 15-month refund effective period. The LPSC has appealed the April and September 2016 orders to the U.S. Court of Appeals for the D.C. Circuit.
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. In July 2009 the Utility operating companies filed a response to the complaint requesting that the FERC dismiss the complaint on the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 explained thatFERC subsequently ordered a hearing in the FERC already had 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 raised no additional claims or facts that would warrant the FERC reaching a different conclusion.proceeding.
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
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Notes to Financial Statements
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, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run 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, excluding interest, that should be paid by Entergy Arkansas to the other 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. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.
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In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludes that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes that any payments by Entergy Arkansas should be reduced by 20%. The LPSC, APSC, City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing the requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denies Entergy’s request for rehearing and affirms FERC’s reviewearlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed, but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account, but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
The effect of the FERC’s decisions, if upheld, is that Entergy Arkansas will make payments to some or all of the other Utility operating companies. As part of the further proceedings required by the FERC, Entergy has performed an initial re-run of the intra-system bills for the ten-year period (2000-2009) to attempt to quantify the effects of the FERC's rulings. The ALJ will issue an initial decision is pending.and FERC will issue an order reviewing that decision. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing thethat initial decision and Entergy submits a subsequent filing to comply with that order. Because further proceedings are required, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case, however, in the first quarter 2016 Entergy Arkansas recorded a liability of $87 million for its estimated increased costs and payment to the other Utility operating companies, including interest. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Therefore Entergy Arkansas recorded a regulatory asset of approximately $75 million, which represents its estimate of the retail portion of the costs.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order addressing the requests for rehearing filed in July 2012. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. Also, in May 2016 a procedural schedule was established with a hearing in May 2017 and an initial decision expected in August 2017. Pursuant to that procedural schedule, Entergy Services re-ran intra-system bills for the ten-year period to quantify the effects of the FERC's ruling. In November 2016 the LPSC submitted testimony disputing certain aspects of the calculations, and Entergy Services submitted answering testimony in January 2017. In February 2017 the FERC staff filed testimony and Entergy Services filed responsive testimony.
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Complaint Against System Energy
In January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy sells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its Grand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The complaint alleges that the return on equity is unjust and unreasonable because current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of reasonable return on equity for System Energy is between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes a return on equity of 8.37% to 8.67% is just and reasonable. Action by the FERC is pending.
Storm Cost Recovery Filings with Retail Regulators
Entergy Arkansas
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 were $63 million, including costs recorded as regulatory assets of approximately $22 million. In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual.
Entergy Louisiana
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. In January 2013, Entergy Louisiana drew $252 million, from its funded storm reserve escrow accounts. In April 2013, Entergy Louisiana filed a joint application withJune 2014 the LPSC relating to Hurricane Isaac system restoration costs. Specifically, Entergy Louisiana requested that the LPSC determine the amount of such costs that were prudently incurred and are, thus, eligible for recovery from customers. Including carrying costs and additional storm escrow funds for prior storms, Entergy Louisiana requested an LPSC determination that $321.5 million in system restoration costs were prudently incurred. In May 2013, 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 Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of the company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amountquantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred ($290.8incurred; (ii) determined $290 million for Entergy Louisiana); (ii) determineas the level of storm reserves to be re-established ($290 million for Entergy Louisiana);re-established; (iii) authorizeauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grantgranted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the LURCLouisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Louisiana issued two series totaling $300 million of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $314.85 million in bonds under Louisiana Act 55. From the $309 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293 million directly to Entergy Louisiana. Entergy Louisiana used the $293 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, and the membership interests have a liquidation price of $100 per unit. The preferred membership interests are callable at the option of
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 $1.75 billion.
Entergy 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 or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collectcollects a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Hurricane Gustav and Hurricane Ike
In September 2008, Hurricane Gustav and Hurricane Ike caused catastrophic damage to Entergy’s service territory. Entergy Louisiana filed its Hurricane Gustav and Hurricane Ike storm cost recovery case with the LPSC in May 2009. In September 2009, Entergy Louisiana and the LURC filed with the LPSC an application requesting that the LPSC grant financing orders authorizing the financing of Entergy Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55.Entergy Louisiana’s Hurricane Katrina and Hurricane Rita storm costs were financed primarily by Louisiana Act 55 financing, as discussed below. Entergy Louisiana also filed an application requesting LPSC approval for ancillary issues including the mechanism to flow charges and Louisiana Act 55 financing savings to customers via a Storm Cost Offset rider.
In December 2009, Entergy Louisiana entered into a stipulation agreement with the LPSC Staffstaff that providesprovided for total recoverable costs of approximately $628 million, including carrying costs. Under this stipulation, Entergy Louisiana agreesagreed not to recover $11.6 million of its storm restoration spending. The stipulation also permitspermitted replenishing Entergy Louisiana’s storm reserve in the amount of $290 million when the Act 55 financings arewere accomplished. In March and April 2010, Entergy Louisiana and other parties to the proceeding filed with the LPSC an uncontested stipulated settlement that includesincluded these terms and also includesincluded Entergy Louisiana’s proposal under the Act 55 financings, which includesincluded a commitment to pass on to customers a minimum of $43.3 million of customer benefits through a prospective annual rate reduction of $8.7 million for five years. A stipulation hearing was held before the ALJ onIn April 13, 2010. On April 21, 2010 the LPSC approved the settlement and subsequently issued financing orders and a ratemaking order intended to facilitate the implementation of the Act 55 financings. In June 2010 the Louisiana State Bond Commission approved the Act 55 financing.
In July 2010, the LCDA issued two series totaling $713.0 million in bonds under Act 55. From the $702.7 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $290 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $412.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy Louisiana used $412.7 million to acquire 4,126,940.15 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 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 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 and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Hurricane 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 storms 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 Louisiana and the LURC filed at the LPSC an application requesting that the LPSC grant a financing order authorizing the financing of Entergy Louisiana storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 55. The Louisiana Act 55 financing is expected to produce additional customer benefits as compared to traditional securitization. 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 Offsetstorm cost offset rider. OnIn April 8, 2008 the Louisiana Public Facilities Authority (LPFA), which is the issuer of the bonds pursuant to the Act 55 financing, approved requests for the Act 55 financing. OnAlso in April 10, 2008, Entergy Louisiana and the LPSC Staffstaff filed with the LPSC an uncontested stipulated settlement that includesincluded Entergy Louisiana’s proposal under the Act 55 financing, which includesincluded a commitment to pass on to customers a minimum of $40 million of customer benefits through a prospective annual rate reduction of $8 million for five years. On April 16, 2008, theThe LPSC subsequently approved the settlement and issued two financing orders and one ratemaking order intended to facilitate implementation of the Act 55 financing. In May 2008 the Louisiana State Bond Commission granted final approval of the Act 55 financing.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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. 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 Louisiana and transferred $187.7 million directly to Entergy Louisiana. From the bond proceeds received by Entergy Louisiana from the LURC, Entergy 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 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 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 or Entergy Louisiana in the event of a bond default. To service the bonds, Entergy Louisiana collect a system restoration charge on behalf of the LURC, and remits the collections to the bond indenture trustee. Entergy and Entergy Louisiana do not report the collections as revenue because Entergy Louisiana is merely acting as the billing and collection agent for the state.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Mississippi
OnIn July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrualprovision should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrualprovision effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrualprovision would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi’s storm damage accrualprovision balance exceeding $15 million as of January 31, 2015, but willwould return to its current level when the storm damage accrualprovision balance becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with the November 2016 billing cycle and will remain at zero until the balance again becomes less than $10 million, at which time it will return to its prior level.
Entergy New Orleans
In October 2006 the City Council approved a rate filing settlement agreement that, among 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 that began in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm.
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 were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among
Entergy Corporation and Subsidiaries
Notes to Financial Statements
other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remainsremained recoverable from Entergy New Orleans’s electric customers. The resolution also directsdirected Entergy New Orleans to file an application to securitize the unrecovered Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it iswas reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achievesachieved the Council-approved funding level of $75 million. In January 2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In April 2015 the City Council’s Utility advisors filed direct testimony recommending that the proposed securitization be approved subject to certain limited modifications, and Entergy New Orleans filed rebuttal testimony later in April 2015. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.
New Nuclear Generation Development Costs
Entergy Louisiana
Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend. In March 2010, Entergy Louisiana and Entergy Gulf States Louisiana filed with the LPSC
Entergy Corporation and Subsidiaries
Notes to Financial Statements
seeking approval to continue the limited development activities necessary to preserve an option to construct a new unit at River Bend. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined 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. The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2015,2016, Entergy Louisiana has a regulatory asset of $50.4$43.1 million on its balance sheet related to these new nuclear generation development costs.
Entergy Mississippi
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was 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 stated 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.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed above. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations
Entergy Corporation and Subsidiaries
Notes to Financial Statements
state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulations, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.
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 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 was 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 gouging accounting scheme” to sell to plaintiffs and similarly situated utility customers higher priced power generated by the defendants while rejecting less expensive power offered from off-system suppliers. In particular, plaintiffs allege that the defendants manipulated and continue
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 as of the date of the report. The Entergy defendants have tendered expert reports challenging the assumptions, methodologies, and conclusions of the plaintiffs’ expert reports.
In March 2012 the state district court found that the case met the requirements to be maintained as a class action under Texas law. In April 2012 the court entered an order certifying the class. The defendants appealed the order to the Texas Court of Appeals – First District and oral argument was held in May 2013. In November 2014 the Texas Court of Appeals - First District reversed the state district court’s class certification order and dismissed the case holding that the state district court lacked subject matter jurisdiction to address the issues. Plaintiffs filed a motion for rehearing and a motion for rehearing en banc. In May 2015 the Court of Appeals granted plaintiffs’ motion for rehearing, withdrew its prior opinion, and set the case for resubmission in June 2015. In July 2015 the Court of Appeals issued a new opinion again finding that the plaintiffs’ claims fall within the exclusive jurisdiction of the FERC and, therefore, the trial court lacked subject matter jurisdiction over the case. The Court of Appeals ordered that the state district court dismiss all claims against the Entergy defendants. In September 2015 plaintiffs filed a petition for review at the Supreme Court of Texas. At the request of the Court, the Entergy defendants filed a response in December 2015. In JanuarySeptember 2016 the Supreme Court denied the plaintiffs’ petition for review. In December 2016 the trial court entered a final judgment of Texas issued an order requiring the partiesdismissal bringing this matter to file briefs on the merits.a conclusion.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 3. INCOME TAXES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Income taxes for 2016, 2015, 2014, and 20132014 for Entergy Corporation and Subsidiaries consist of the following:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Current: | | | | | | | | | | |
| Federal |
| $77,166 |
| |
| $90,061 |
| |
| $88,291 |
|
| $45,249 |
| |
| $77,166 |
| |
| $90,061 |
|
| Foreign | 97 |
| | 90 |
| | 101 |
| 68 |
| | 97 |
| | 90 |
|
| State | 157,829 |
| | (12,637 | ) | | 20,584 |
| (14,960 | ) | | 157,829 |
| | (12,637 | ) |
| Total | 235,092 |
| | 77,514 |
| | 108,976 |
| 30,357 |
| | 235,092 |
| | 77,514 |
|
| Deferred and non-current - net | (864,799 | ) | | 528,326 |
| | 126,935 |
| (840,465 | ) | | (864,799 | ) | | 528,326 |
|
| Investment tax credit adjustments - net | (13,220 | ) | | (16,243 | ) | | (9,930 | ) | (7,151 | ) | | (13,220 | ) | | (16,243 | ) |
| Income taxes |
| ($642,927 | ) | |
| $589,597 |
| |
| $225,981 |
|
| ($817,259 | ) | |
| ($642,927 | ) | |
| $589,597 |
|
Income taxes for 2016, 2015, and 2014 for Entergy’s Registrant Subsidiaries consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| ($14,748 | ) | |
| ($124,113 | ) | |
| $10,603 |
| |
| ($91,067 | ) | |
| $19,656 |
| |
| $29,628 |
|
| State | | 2,805 |
| | 10,757 |
| | 2,257 |
| | 566 |
| | 1,374 |
| | (25,825 | ) |
| Total | | (11,943 | ) | | (113,356 | ) | | 12,860 |
| | (90,501 | ) | | 21,030 |
| | 3,803 |
|
| Deferred and non-current - net | | 120,942 |
| | 208,157 |
| | 46,984 |
| | 119,345 |
| | 42,982 |
| | 71,051 |
|
| Investment tax credit adjustments - net | | (1,226 | ) | | (5,067 | ) | | 4,010 |
| | (139 | ) | | (915 | ) | | (3,793 | ) |
| Income taxes | |
| $107,773 |
| |
| $89,734 |
| |
| $63,854 |
| |
| $28,705 |
| |
| $63,097 |
| |
| $71,061 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| $66,966 |
| |
| $101,382 |
| |
| $25,628 |
| |
| ($9,346 | ) | |
| $53,313 |
| |
| ($63,302 | ) |
| State | | 6,265 |
| | 35,406 |
| | 6,832 |
| | 1,784 |
| | 2,450 |
| | 26,755 |
|
| Total | | 73,231 |
| | 136,788 |
| | 32,460 |
| | (7,562 | ) | | 55,763 |
| | (36,547 | ) |
| Deferred and non-current - net | | (31,463 | ) | | 47,220 |
| | 31,149 |
| | 32,890 |
| | (17,599 | ) | | 93,491 |
|
| Investment tax credit adjustments - net | | (1,227 | ) | | (5,337 | ) | | (1,737 | ) | | (138 | ) | | (914 | ) | | (3,867 | ) |
| Income taxes | |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Income taxes for 2015, 2014, and 2013 for Entergy’s Registrant Subsidiaries consist of the following:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| $66,966 |
| |
| $101,382 |
| |
| $25,628 |
| |
| ($9,346 | ) | |
| $53,313 |
| |
| ($63,302 | ) |
| State | | 6,265 |
| | 35,406 |
| | 6,832 |
| | 1,784 |
| | 2,450 |
| | 26,755 |
|
| Total | | 73,231 |
| | 136,788 |
| | 32,460 |
| | (7,562 | ) | | 55,763 |
| | (36,547 | ) |
| Deferred and non-current - net | | (31,463 | ) | | 47,220 |
| | 31,149 |
| | 32,890 |
| | (17,599 | ) | | 93,491 |
|
| Investment tax credit adjustments - net | | (1,227 | ) | | (5,337 | ) | | (1,737 | ) | | (138 | ) | | (914 | ) | | (3,867 | ) |
| Income taxes | |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
|
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Current: | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal | |
| ($34,258 | ) | |
| ($44,909 | ) | |
| $8,103 |
| |
| ($1,428 | ) | |
| $48,610 |
| |
| $19,908 |
| |
| ($34,258 | ) | |
| ($44,909 | ) | |
| $8,103 |
| |
| ($1,428 | ) | |
| $48,610 |
| |
| $19,908 |
|
| State | | (678 | ) | | (1,191 | ) | | 7,474 |
| | 510 |
| | 4,877 |
| | 15,379 |
| | (678 | ) | | (1,191 | ) | | 7,474 |
| | 510 |
| | 4,877 |
| | 15,379 |
|
| Total | | (34,936 | ) | | (46,100 | ) | | 15,577 |
| | (918 | ) | | 53,487 |
| | 35,287 |
| | (34,936 | ) | | (46,100 | ) | | 15,577 |
| | (918 | ) | | 53,487 |
| | 35,287 |
|
| Deferred and non-current - net | | 119,841 |
| | 236,794 |
| | 42,305 |
| | 14,592 |
| | (2,418 | ) | | 53,501 |
| | 119,841 |
| | 236,794 |
| | 42,305 |
| | 14,592 |
| | (2,418 | ) | | 53,501 |
|
| Investment tax credit adjustments - net | | (1,276 | ) | | (5,642 | ) | | (2,172 | ) | | (224 | ) | | (1,425 | ) | | (5,478 | ) | | (1,276 | ) | | (5,642 | ) | | (2,172 | ) | | (224 | ) | | (1,425 | ) | | (5,478 | ) |
| Income taxes | |
| $83,629 |
| |
| $185,052 |
| |
| $55,710 |
| |
| $13,450 |
| |
| $49,644 |
| |
| $83,310 |
| |
| $83,629 |
| |
| $185,052 |
| |
| $55,710 |
| |
| $13,450 |
| |
| $49,644 |
| |
| $83,310 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Current: | | | | | | | | | | | | |
| Federal | |
| ($13,574 | ) | |
| ($18,797 | ) | |
| $2,498 |
| |
| $14,823 |
| |
| $37,199 |
| |
| ($6,199 | ) |
| State | | 6,122 |
| | (15,631 | ) | | 4,849 |
| | (1,267 | ) | | (843 | ) | | 15,845 |
|
| Total | | (7,452 | ) | | (34,428 | ) | | 7,347 |
| | 13,556 |
| | 36,356 |
| | 9,646 |
|
| Deferred and non-current - net | | 101,253 |
| | 179,036 |
| | 41,150 |
| | (11,033 | ) | | (4,639 | ) | | 60,614 |
|
| Investment tax credit adjustments - net | | (2,014 | ) | | (5,912 | ) | | 1,260 |
| | (246 | ) | | (1,609 | ) | | (1,407 | ) |
| Income taxes | |
| $91,787 |
| |
| $138,696 |
| |
| $49,757 |
| |
| $2,277 |
| |
| $30,108 |
| |
| $68,853 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total income taxes for Entergy Corporation and Subsidiaries 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 2016, 2015, 2014, and 20132014 are:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Net income (loss) attributable to Entergy Corporation |
| ($176,562 | ) | |
| $940,721 |
| |
| $711,902 |
|
| ($583,618 | ) | |
| ($176,562 | ) | |
| $940,721 |
|
| Preferred dividend requirements of subsidiaries | 19,828 |
| | 19,536 |
| | 18,670 |
| 19,115 |
| | 19,828 |
| | 19,536 |
|
| Consolidated net income (loss) | (156,734 | ) | | 960,257 |
| | 730,572 |
| (564,503 | ) | | (156,734 | ) | | 960,257 |
|
| Income taxes | (642,927 | ) | | 589,597 |
| | 225,981 |
| (817,259 | ) | | (642,927 | ) | | 589,597 |
|
| Income (loss) before income taxes |
| ($799,661 | ) | |
| $1,549,854 |
| |
| $956,553 |
|
| ($1,381,762 | ) | |
| ($799,661 | ) | |
| $1,549,854 |
|
| Computed at statutory rate (35%) |
| ($279,881 | ) | |
| $542,449 |
| |
| $334,794 |
|
| ($483,617 | ) | |
| ($279,881 | ) | |
| $542,449 |
|
| Increases (reductions) in tax resulting from: | |
| | |
| | |
| |
| | |
| | |
|
| State income taxes net of federal income tax effect | 29,944 |
| | 44,708 |
| | 13,599 |
| 40,581 |
| | 29,944 |
| | 44,708 |
|
| Regulatory differences - utility plant items | 32,089 |
| | 39,321 |
| | 32,324 |
| 33,581 |
| | 32,089 |
| | 39,321 |
|
| Equity component of AFUDC | (18,191 | ) | | (21,108 | ) | | (22,356 | ) | (23,647 | ) | | (18,191 | ) | | (21,108 | ) |
| Amortization of investment tax credits | (11,136 | ) | | (12,211 | ) | | (13,535 | ) | (10,889 | ) | | (11,136 | ) | | (12,211 | ) |
| Flow-through / permanent differences | (7,872 | ) | | (18,003 | ) | | (301 | ) | (19,307 | ) | | (7,872 | ) | | (18,003 | ) |
| Net-of-tax regulatory liability | — |
| | — |
| | (2,899 | ) | |
| New York tax law change (a) | — |
| | (21,500 | ) | | — |
| — |
| | — |
| | (21,500 | ) |
| Louisiana business combination | (333,655 | ) | | — |
| | — |
| — |
| | (333,655 | ) | | — |
|
| Termination of business reorganization | — |
| | — |
| | (27,192 | ) | |
| Provision for uncertain tax positions (b) | (56,683 | ) | | 32,573 |
| | (59,249 | ) | |
| Entergy Wholesale Commodities restructuring (b) | | (237,760 | ) | | — |
| | — |
|
| Act 55 financing settlement (d) | | (63,477 | ) | | — |
| | — |
|
| Provision for uncertain tax positions (c) (d) | | (67,119 | ) | | (56,683 | ) | | 32,573 |
|
| Valuation allowance | — |
| | — |
| | (31,573 | ) | 11,411 |
| | — |
| | — |
|
| Other - net | 2,458 |
| | 3,368 |
| | 2,369 |
| 2,984 |
| | 2,458 |
| | 3,368 |
|
| Total income taxes as reported |
| ($642,927 | ) | |
| $589,597 |
| |
| $225,981 |
|
| ($817,259 | ) | |
| ($642,927 | ) | |
| $589,597 |
|
| Effective Income Tax Rate | 80.4 | % | | 38.0 | % | | 23.6 | % | 59.1 | % | | 80.4 | % | | 38.0 | % |
| |
| (a) | In March 2014, New York enacted legislation that substantially modifiesmodified various aspects of New York tax law. The most significant effect of the legislation for Entergy iswas the adoption of full water’s-edge unitary combined reporting, meaning that all of Entergy’s domestic entities will be included in New York’s combined filing group. The effect of the tax law change resulted in a deferred state income tax reduction of approximately $21.5 million as shown in the table above. |
| |
| (b) | See “Other Tax Matters” below for discussion of the Entergy Wholesale Commodities restructuring. |
| |
| (c) | See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for 2015 and 2013.2015. |
| |
| (d) | See “Income Tax Audits- 2010-2011 IRS Audit” below for discussion of the most significant items for 2016. |
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 2016, 2015, 2014, and 20132014 are:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net income | |
| $74,272 |
| |
| $446,639 |
| |
| $92,708 |
| |
| $44,925 |
| |
| $69,625 |
| |
| $111,318 |
| |
| $167,212 |
| |
| $622,047 |
| |
| $109,184 |
| |
| $48,849 |
| |
| $107,538 |
| |
| $96,744 |
|
| Income taxes | | 40,541 |
| | 178,671 |
| | 61,872 |
| | 25,190 |
| | 37,250 |
| | 53,077 |
| | 107,773 |
| | 89,734 |
| | 63,854 |
| | 28,705 |
| | 63,097 |
| | 71,061 |
|
| Pretax income | |
| $114,813 |
| |
| $625,310 |
| |
| $154,580 |
| |
| $70,115 |
| |
| $106,875 |
| |
| $164,395 |
| |
| $274,985 |
| |
| $711,781 |
| |
| $173,038 |
| |
| $77,554 |
| |
| $170,635 |
| |
| $167,805 |
|
| Computed at statutory rate (35%) | |
| $40,185 |
| |
| $218,859 |
| |
| $54,103 |
| |
| $24,540 |
| |
| $37,406 |
| |
| $57,538 |
| |
| $96,245 |
| |
| $249,123 |
| |
| $60,563 |
| |
| $27,144 |
| |
| $59,722 |
| |
| $58,732 |
|
| Increases (reductions) in tax resulting from: | | | | |
| | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 6,643 |
| | 23,650 |
| | 5,219 |
| | 2,887 |
| | 1,621 |
| | 6,403 |
| | 11,652 |
| | 29,014 |
| | 5,592 |
| | 3,543 |
| | 449 |
| | 7,001 |
|
| Regulatory differences - utility plant items | | 7,299 |
| | 3,013 |
| | 2,383 |
| | 2,201 |
| | 3,703 |
| | 12,167 |
| | 10,971 |
| | 8,094 |
| | (1,154 | ) | | 2,329 |
| | 4,140 |
| | 9,201 |
|
| Equity component of AFUDC | | (4,979 | ) | | (5,420 | ) | | (1,083 | ) | | (451 | ) | | (1,987 | ) | | (2,973 | ) | | (5,985 | ) | | (9,774 | ) | | (2,030 | ) | | (412 | ) | | (2,666 | ) | | (2,780 | ) |
| Amortization of investment tax credits | | (1,201 | ) | | (5,252 | ) | | (160 | ) | | (111 | ) | | (900 | ) | | (3,476 | ) | | (1,201 | ) | | (5,019 | ) | | (160 | ) | | (132 | ) | | (900 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | (4,062 | ) | | 2,460 |
| | 431 |
| | (4,539 | ) | | 530 |
| | 618 |
| | (3,848 | ) | | (980 | ) | | 764 |
| | (3,609 | ) | | 634 |
| | (883 | ) |
| Act 55 financing settlement (a) | | | — |
| | (61,620 | ) | | — |
| | — |
| | (454 | ) | | — |
|
| Non-taxable dividend income | | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions (a) | | (3,978 | ) | | (15,377 | ) | | 756 |
| | 525 |
| | (3,365 | ) | | (17,313 | ) | | (717 | ) | | (75,871 | ) | | 50 |
| | (300 | ) | | 1,926 |
| | 3,151 |
|
| Other - net | | 634 |
| | 1,396 |
| | 223 |
| | 138 |
| | 242 |
| | 113 |
| | 656 |
| | 1,425 |
| | 229 |
| | 142 |
| | 246 |
| | 115 |
|
| Total income taxes | |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
| |
| Total income taxes as reported | | |
| $107,773 |
| |
| $89,734 |
| |
| $63,854 |
| |
| $28,705 |
| |
| $63,097 |
| |
| $71,061 |
|
| Effective Income Tax Rate | | 35.3 | % | | 28.6 | % | | 40.0 | % | | 35.9 | % | | 34.9 | % | | 32.3 | % | | 39.2 | % | | 12.6 | % | | 36.9 | % | | 37.0 | % | | 37.0 | % | | 42.3 | % |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $74,272 |
| |
| $446,639 |
| |
| $92,708 |
| |
| $44,925 |
| |
| $69,625 |
| |
| $111,318 |
|
| Income taxes | | 40,541 |
| | 178,671 |
| | 61,872 |
| | 25,190 |
| | 37,250 |
| | 53,077 |
|
| Pretax income | |
| $114,813 |
| |
| $625,310 |
| |
| $154,580 |
| |
| $70,115 |
| |
| $106,875 |
| |
| $164,395 |
|
| Computed at statutory rate (35%) | |
| $40,185 |
| |
| $218,859 |
| |
| $54,103 |
| |
| $24,540 |
| |
| $37,406 |
| |
| $57,538 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 6,643 |
| | 23,650 |
| | 5,219 |
| | 2,887 |
| | 1,621 |
| | 6,403 |
|
| Regulatory differences - utility plant items | | 7,299 |
| | 3,013 |
| | 2,383 |
| | 2,201 |
| | 3,703 |
| | 12,167 |
|
| Equity component of AFUDC | | (4,979 | ) | | (5,420 | ) | | (1,083 | ) | | (451 | ) | | (1,987 | ) | | (2,973 | ) |
| Amortization of investment tax credits | | (1,201 | ) | | (5,252 | ) | | (160 | ) | | (111 | ) | | (900 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | (4,062 | ) | | 2,460 |
| | 431 |
| | (4,539 | ) | | 530 |
| | 618 |
|
| Non-taxable dividend income | | — |
| | (44,658 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions (b) | | (3,978 | ) | | (15,377 | ) | | 756 |
| | 525 |
| | (3,365 | ) | | (17,313 | ) |
| Other - net | | 634 |
| | 1,396 |
| | 223 |
| | 138 |
| | 242 |
| | 113 |
|
| Total income taxes as reported | |
| $40,541 |
| |
| $178,671 |
| |
| $61,872 |
| |
| $25,190 |
| |
| $37,250 |
| |
| $53,077 |
|
| Effective Income Tax Rate | | 35.3 | % | | 28.6 | % | | 40.0 | % | | 35.9 | % | | 34.9 | % | | 32.3 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $121,392 |
| |
| $446,022 |
| |
| $74,821 |
| |
| $31,030 |
| |
| $74,804 |
| |
| $96,334 |
|
| Income taxes | | 83,629 |
| | 185,052 |
| | 55,710 |
| | 13,450 |
| | 49,644 |
| | 83,310 |
|
| Pretax income | |
| $205,021 |
| |
| $631,074 |
| |
| $130,531 |
| |
| $44,480 |
| |
| $124,448 |
| |
| $179,644 |
|
| Computed at statutory rate (35%) | |
| $71,757 |
| |
| $220,876 |
| |
| $45,686 |
| |
| $15,568 |
| |
| $43,557 |
| |
| $62,875 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 9,591 |
| | 11,666 |
| | 5,180 |
| | 1,562 |
| | 3,221 |
| | 6,877 |
|
| Regulatory differences - utility plant items | | 8,653 |
| | 7,487 |
| | 4,448 |
| | 777 |
| | 4,165 |
| | 13,791 |
|
| Equity component of AFUDC | | (2,533 | ) | | (14,612 | ) | | (833 | ) | | (320 | ) | | (1,035 | ) | | (1,774 | ) |
| Amortization of investment tax credits | | (1,251 | ) | | (5,594 | ) | | (260 | ) | | (218 | ) | | (1,412 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | (5,082 | ) | | (225 | ) | | 555 |
| | (4,458 | ) | | 393 |
| | (327 | ) |
| Non-taxable dividend income | | — |
| | (41,255 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions | | 1,881 |
| | 5,336 |
| | 718 |
| | 405 |
| | 522 |
| | 5,235 |
|
| Other - net | | 613 |
| | 1,373 |
| | 216 |
| | 134 |
| | 233 |
| | 109 |
|
| Total income taxes as reported | |
| $83,629 |
| |
| $185,052 |
| |
| $55,710 |
| |
| $13,450 |
| |
| $49,644 |
| |
| $83,310 |
|
| Effective Income Tax Rate | | 40.8 | % | | 29.3 | % | | 42.7 | % | | 30.2 | % | | 39.9 | % | | 46.4 | % |
| |
| (a) | See “Income Tax Audits- 2010-2011 IRS Audit” below for discussion of the most significant items for Entergy Louisiana. |
| |
| (b) | See “Income Tax Audits - 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $121,392 |
| |
| $446,022 |
| |
| $74,821 |
| |
| $31,030 |
| |
| $74,804 |
| |
| $96,334 |
|
| Income taxes | | 83,629 |
| | 185,052 |
| | 55,710 |
| | 13,450 |
| | 49,644 |
| | 83,310 |
|
| Pretax income | |
| $205,021 |
| |
| $631,074 |
| |
| $130,531 |
| |
| $44,480 |
| |
| $124,448 |
| |
| $179,644 |
|
| Computed at statutory rate (35%) | |
| $71,757 |
| |
| $220,876 |
| |
| $45,686 |
| |
| $15,568 |
| |
| $43,557 |
| |
| $62,875 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 9,591 |
| | 11,666 |
| | 5,180 |
| | 1,562 |
| | 3,221 |
| | 6,877 |
|
| Regulatory differences - utility plant items | | 8,653 |
| | 7,487 |
| | 4,448 |
| | 777 |
| | 4,165 |
| | 13,791 |
|
| Equity component of AFUDC | | (2,533 | ) | | (14,612 | ) | | (833 | ) | | (320 | ) | | (1,035 | ) | | (1,774 | ) |
| Amortization of investment tax credits | | (1,251 | ) | | (5,594 | ) | | (260 | ) | | (218 | ) | | (1,412 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | (5,082 | ) | | (225 | ) | | 555 |
| | (4,458 | ) | | 393 |
| | (327 | ) |
| Non-taxable dividend income | | — |
| | (41,255 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions | | 1,881 |
| | 5,336 |
| | 718 |
| | 405 |
| | 522 |
| | 5,235 |
|
| Other - net | | 613 |
| | 1,373 |
| | 216 |
| | 134 |
| | 233 |
| | 109 |
|
| Total income taxes | |
| $83,629 |
| |
| $185,052 |
| |
| $55,710 |
| |
| $13,450 |
| |
| $49,644 |
| |
| $83,310 |
|
| Effective Income Tax Rate | | 40.8 | % | | 29.3 | % | | 42.7 | % | | 30.2 | % | | 39.9 | % | | 46.4 | % |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Net income | |
| $161,948 |
| |
| $414,126 |
| |
| $82,159 |
| |
| $12,608 |
| |
| $57,881 |
| |
| $113,664 |
|
| Income taxes | | 91,787 |
| | 138,696 |
| | 49,757 |
| | 2,277 |
| | 30,108 |
| | 68,853 |
|
| Pretax income | |
| $253,735 |
| |
| $552,822 |
| |
| $131,916 |
| |
| $14,885 |
| |
| $87,989 |
| |
| $182,517 |
|
| Computed at statutory rate (35%) | |
| $88,807 |
| |
| $193,488 |
| |
| $46,171 |
| |
| $5,210 |
| |
| $30,796 |
| |
| $63,881 |
|
| Increases (reductions) in tax resulting from: | | |
| | |
| | |
| | |
| | |
| | |
|
| State income taxes net of federal income tax effect | | 10,954 |
| | 19,084 |
| | 4,564 |
| | 1,116 |
| | (897 | ) | | 5,900 |
|
| Regulatory differences - utility plant items | | 7,938 |
| | 7,005 |
| | 2,603 |
| | 453 |
| | 3,256 |
| | 11,070 |
|
| Equity component of AFUDC | | (3,820 | ) | | (13,100 | ) | | (764 | ) | | (322 | ) | | (1,626 | ) | | (2,724 | ) |
| Amortization of investment tax credits | | (1,989 | ) | | (5,864 | ) | | (260 | ) | | (216 | ) | | (1,596 | ) | | (3,476 | ) |
| Flow-through / permanent differences | | 2,540 |
| | 3,646 |
| | 1,702 |
| | (4,402 | ) | | 2,467 |
| | (491 | ) |
| Net-of-tax regulatory liability | | — |
| | (2,899 | ) | | — |
| | — |
| | — |
| | — |
|
| Termination of business organization | | (6,753 | ) | | (7,453 | ) | | (4,177 | ) | | (501 | ) | | (3,542 | ) | | (13 | ) |
| Non-taxable dividend income | | — |
| | (36,953 | ) | | — |
| | — |
| | — |
| | — |
|
| Provision for uncertain tax positions (a) | | (6,527 | ) | | (18,645 | ) | | (326 | ) | | 795 |
| | 1,027 |
| | (5,353 | ) |
| Other - net | | 637 |
| | 387 |
| | 244 |
| | 144 |
| | 223 |
| | 59 |
|
| Total income taxes | |
| $91,787 |
| |
| $138,696 |
| |
| $49,757 |
| |
| $2,277 |
| |
| $30,108 |
| |
| $68,853 |
|
| Effective Income Tax Rate | | 36.2 | % | | 25.1 | % | | 37.7 | % | | 15.3 | % | | 34.2 | % | | 37.7 | % |
| |
(a) | See “Income Tax Audits- 2008-2009 IRS Audit” below for discussion of the most significant items for Entergy Louisiana and System Energy.
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Significant components of accumulated deferred income taxes and taxes accrued for Entergy Corporation and Subsidiaries as of December 31, 20152016 and 20142015 are as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Deferred tax liabilities: | | | | | | |
| Plant basis differences - net |
| ($6,804,225 | ) | |
| ($8,128,096 | ) |
| ($6,362,905 | ) | |
| ($6,804,225 | ) |
| Regulatory assets | (646,392 | ) | | (922,161 | ) | (584,572 | ) | | (646,392 | ) |
| Nuclear decommissioning trusts | (1,254,463 | ) | | (1,248,737 | ) | |
| Nuclear decommissioning trusts/receivables | | (1,739,977 | ) | | (1,254,463 | ) |
| Pension, net funding | (365,111 | ) | | (324,881 | ) | (429,896 | ) | | (365,111 | ) |
| Combined unitary state taxes | (45,078 | ) | | (162,340 | ) | (33,063 | ) | | (45,078 | ) |
| Power purchase agreements | — |
| | (110,889 | ) | (993 | ) | | — |
|
| Other | (315,844 | ) | | (500,424 | ) | (251,719 | ) | | (315,844 | ) |
| Total | (9,431,113 | ) | | (11,397,528 | ) | (9,403,125 | ) | | (9,431,113 | ) |
| Deferred tax assets: | |
| | |
| |
| | |
|
| Nuclear decommissioning liabilities | 828,983 |
| | 874,493 |
| 1,399,468 |
| | 828,983 |
|
| Regulatory liabilities | 284,432 |
| | 458,230 |
| 255,272 |
| | 284,432 |
|
| Pension and other post-employment benefits | 525,524 |
| | 586,455 |
| 539,456 |
| | 525,524 |
|
| Sale and leaseback | 139,720 |
| | 153,308 |
| 135,866 |
| | 139,720 |
|
| Compensation | 69,432 |
| | 74,692 |
| 99,300 |
| | 69,432 |
|
| Accumulated deferred investment tax credit | 95,248 |
| | 100,442 |
| 92,375 |
| | 95,248 |
|
| Provision for allowances and contingencies | 188,282 |
| | 160,551 |
| 188,390 |
| | 188,282 |
|
| Power purchase agreements | 38,401 |
| | — |
| — |
| | 38,401 |
|
| Net operating loss carryforwards | 360,188 |
| | 457,758 |
| 334,025 |
| | 360,188 |
|
| Capital losses and miscellaneous tax credits | 11,075 |
| | 12,146 |
| 18,470 |
| | 11,075 |
|
| Valuation allowance | (91,532 | ) | | (27,387 | ) | (104,277 | ) | | (91,532 | ) |
| Other | 68,204 |
| | 58,334 |
| 59,079 |
| | 68,204 |
|
| Total | 2,517,957 |
| | 2,909,022 |
| 3,017,424 |
| | 2,517,957 |
|
| Non-current accrued taxes (including unrecognized tax benefits) | (1,338,806 | ) | | (606,560 | ) | (991,704 | ) | | (1,338,806 | ) |
| Accumulated deferred income taxes and taxes accrued |
| ($8,251,962 | ) | |
| ($9,095,066 | ) |
| ($7,377,405 | ) | |
| ($8,251,962 | ) |
Entergy’s estimated tax attributes carryovers and their expiration dates as of December 31, 20152016 are as follows:
|
| | | | |
| Carryover Description | | Carryover Amount | | Year(s) of expiration |
| | | | | |
| Federal net operating losses | | $3.66.7 billion | | 2023-20352023-2036 |
| State net operating losses | | $5.27.8 billion | | 2016-20352017-2036 |
| Miscellaneous federal and state credits | | $77.989.9 million | | 2016-20352017-2036 |
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. Because it is more likely than not that the benefit from certain state net operating loss carryovers will not be utilized, valuation allowances of $62 million as of December 31, 2016 and $46 million as of December 31, 2015 and $21 million as of December 31, 2014 have been provided on the deferred tax assets relating to these state net operating loss carryovers. Additionally, valuation allowances totaling $42.3 million as of December 31, 2016 and $45.5 million as of December 31, 2015 have been provided on deferred tax assets related to federal and
Entergy Corporation and Subsidiaries
Notes to Financial Statements
state jurisdictions in which Entergy does not currently expect to be able to utilize separate company tax return losses, preventing realization of such deferred tax assets.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Significant components of accumulated deferred income taxes and taxes accrued for the Registrant Subsidiaries as of December 31, 20152016 and 20142015 are as follows:
| | | 2015 | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | | (In Thousands) |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | |
| Plant basis differences - net |
| ($1,710,444 | ) | |
| ($2,041,968 | ) | |
| ($781,427 | ) | |
| ($167,294 | ) | |
| ($778,270 | ) | |
| ($611,745 | ) | |
| ($1,857,554 | ) | |
| ($2,357,599 | ) | |
| ($820,971 | ) | |
| ($177,242 | ) | |
| ($835,671 | ) | |
| ($651,394 | ) |
| Regulatory assets | (108,422 | ) | | (254,316 | ) | | (24,918 | ) | | (39,451 | ) | | (172,117 | ) | | (46,990 | ) | | (109,241 | ) | | (219,750 | ) | | (25,309 | ) | | (36,301 | ) | | (153,914 | ) | | (39,879 | ) |
| Nuclear decommissioning trusts | (121,326 | ) | | (99,980 | ) | | — |
| | — |
| | — |
| | (68,370 | ) | |
| Nuclear decommissioning trusts/receivables | | | (144,250 | ) | | (119,544 | ) | | — |
| | — |
| | — |
| | (83,891 | ) |
| Pension, net funding | (107,073 | ) | | (109,709 | ) | | (30,901 | ) | | (14,459 | ) | | (28,001 | ) | | (25,791 | ) | | (123,889 | ) | | (122,465 | ) | | (34,284 | ) | | (16,307 | ) | | (28,371 | ) | | (29,357 | ) |
| Deferred fuel | (7,647 | ) | | (2,513 | ) | | (684 | ) | | (175 | ) | | 2,050 |
| | (18 | ) | | (14,774 | ) | | (1,778 | ) | | (12,770 | ) | | (5,229 | ) | | (2,808 | ) | | (1,137 | ) |
| Other | (38,683 | ) | | (86,275 | ) | | (5,625 | ) | | (12,253 | ) | | (10,109 | ) | | (22,478 | ) | | (47,785 | ) | | (22,136 | ) | | (12,474 | ) | | (18,536 | ) | | (8,812 | ) | | (2,051 | ) |
| Total | (2,093,595 | ) | | (2,594,761 | ) | | (843,555 | ) | | (233,632 | ) | | (986,447 | ) | | (775,392 | ) | | (2,297,493 | ) | | (2,843,272 | ) | | (905,808 | ) | | (253,615 | ) | | (1,029,576 | ) | | (807,709 | ) |
| Deferred tax assets: | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Regulatory liabilities | 18,369 |
| | 215,154 |
| | 7,787 |
| | 20,888 |
| | 7,307 |
| | 14,927 |
| | 5,768 |
| | 175,973 |
| | 18,833 |
| | 25,240 |
| | 15,814 |
| | 13,644 |
|
| Nuclear decommissioning liabilities | 109,962 |
| | 49,333 |
| | — |
| | — |
| | — |
| | 39,420 |
| | 124,206 |
| | 55,408 |
| | — |
| | — |
| | — |
| | 53,113 |
|
| Pension and other post-employment benefits | (20,420 | ) | | 149,680 |
| | (6,628 | ) | | (8,939 | ) | | (16,703 | ) | | (1,037 | ) | | (24,467 | ) | | 145,401 |
| | (8,042 | ) | | (12,070 | ) | | (19,096 | ) | | (1,182 | ) |
| Sale and leaseback | — |
| | 37,236 |
| | — |
| | — |
| | — |
| | 102,484 |
| | — |
| | 33,383 |
| | — |
| | — |
| | — |
| | 102,483 |
|
| Accumulated deferred investment tax credit | 14,320 |
| | 56,635 |
| | 1,777 |
| | 290 |
| | 4,842 |
| | 17,385 |
| | 13,848 |
| | 54,509 |
| | 3,315 |
| | 239 |
| | 4,527 |
| | 15,936 |
|
| Provision for allowances and contingencies | 1,024 |
| | 123,007 |
| | 18,735 |
| | 33,843 |
| | 7,266 |
| | 134 |
| | (1,497 | ) | | 124,309 |
| | 21,817 |
| | 36,466 |
| | 5,904 |
| | — |
|
| Power purchase agreements | (1,279 | ) | | 13,840 |
| | 1,901 |
| | 13 |
| | 575 |
| | — |
| | (3,094 | ) | | 29,827 |
| | 1,905 |
| | — |
| | 140 |
| | — |
|
| Unbilled/deferred revenues | 9,815 |
| | (32,365 | ) | | 7,154 |
| | 2,126 |
| | 10,851 |
| | — |
| | 6,799 |
| | (35,006 | ) | | 5,085 |
| | 3,751 |
| | 11,902 |
| | — |
|
| Compensation | 1,842 |
| | 4,182 |
| | 601 |
| | 880 |
| | 4,496 |
| | — |
| | 2,787 |
| | 5,309 |
| | 1,492 |
| | 685 |
| | 1,587 |
| | 360 |
|
| Net operating loss carryforwards | — |
| | 90,241 |
| | — |
| | — |
| | — |
| | — |
| | 69,524 |
| | 17,125 |
| | — |
| | — |
| | — |
| | — |
|
| Capital losses and miscellaneous tax credits | | | 2,074 |
| | — |
| | 4,487 |
| | — |
| | — |
| | — |
|
| Other | 128 |
| | 21,982 |
| | 1,995 |
| | 316 |
| | 1,672 |
| | — |
| | 174 |
| | 17,110 |
| | 1,152 |
| | 496 |
| | 2,955 |
| | — |
|
| Total | 133,761 |
| | 728,925 |
| | 33,322 |
| | 49,417 |
| | 20,306 |
| | 173,313 |
| | 196,122 |
| | 623,348 |
| | 50,044 |
| | 54,807 |
| | 23,733 |
| | 184,354 |
|
| Non-current accrued taxes (including unrecognized tax benefits) | (22,978 | ) | | (641,120 | ) | | (402 | ) | | (29,846 | ) | | (40,693 | ) | | (416,996 | ) | | (85,252 | ) | | (471,194 | ) | | (5,567 | ) | | (136,145 | ) | | (21,804 | ) | | (489,510 | ) |
| Accumulated deferred income taxes and taxes accrued |
| ($1,982,812 | ) | |
| ($2,506,956 | ) | |
| ($810,635 | ) | |
| ($214,061 | ) | |
| ($1,006,834 | ) | |
| ($1,019,075 | ) | |
| ($2,186,623 | ) | |
| ($2,691,118 | ) | |
| ($861,331 | ) | |
| ($334,953 | ) | |
| ($1,027,647 | ) | |
| ($1,112,865 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Deferred tax liabilities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Plant basis differences - net | |
| ($1,657,503 | ) | |
| ($2,748,852 | ) | |
| ($753,576 | ) | |
| ($186,153 | ) | |
| ($771,135 | ) | |
| ($668,779 | ) | |
| ($1,710,444 | ) | |
| ($2,041,968 | ) | |
| ($781,427 | ) | |
| ($167,294 | ) | |
| ($778,270 | ) | |
| ($611,745 | ) |
| Regulatory assets | | (198,662 | ) | | (380,719 | ) | | (30,114 | ) | | — |
| | (202,402 | ) | | (110,087 | ) | | (108,422 | ) | | (254,316 | ) | | (24,918 | ) | | (39,451 | ) | | (172,117 | ) | | (46,990 | ) |
| Nuclear decommissioning trusts | | (130,524 | ) | | (106,162 | ) | | — |
| | — |
| | — |
| | (74,063 | ) | | (121,326 | ) | | (99,980 | ) | | — |
| | — |
| | — |
| | (68,370 | ) |
| Pension, net funding | | (93,355 | ) | | (99,593 | ) | | (27,861 | ) | | (13,285 | ) | | (25,616 | ) | | (23,440 | ) | | (107,073 | ) | | (109,709 | ) | | (30,901 | ) | | (14,459 | ) | | (28,001 | ) | | (25,791 | ) |
| Deferred fuel | | (82,050 | ) | | (3,534 | ) | | (5,303 | ) | | (407 | ) | | 2,045 |
| | (120 | ) | | (7,647 | ) | | (2,513 | ) | | (684 | ) | | (175 | ) | | 2,050 |
| | (18 | ) |
| Power purchase agreements | | (17,073 | ) | | (67,083 | ) | | 2,129 |
| | 13 |
| | 847 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Other | | (33,827 | ) | | (84,282 | ) | | (11,423 | ) | | (11,500 | ) | | (22,546 | ) | | (19,802 | ) | | (38,683 | ) | | (86,275 | ) | | (5,625 | ) | | (12,253 | ) | | (10,109 | ) | | (22,478 | ) |
| Total | | (2,212,994 | ) | | (3,490,225 | ) | | (826,148 | ) | | (211,332 | ) | | (1,018,807 | ) | | (896,291 | ) | | (2,093,595 | ) | | (2,594,761 | ) | | (843,555 | ) | | (233,632 | ) | | (986,447 | ) | | (775,392 | ) |
| Deferred tax assets: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Regulatory liabilities | | 145,466 |
| | 181,601 |
| | 7,214 |
| | 29,580 |
| | 4,079 |
| | 90,290 |
| | 18,369 |
| | 215,154 |
| | 7,787 |
| | 20,888 |
| | 7,307 |
| | 14,927 |
|
| Nuclear decommissioning liabilities | | (43,134 | ) | | 146,138 |
| | — |
| | — |
| | — |
| | (62,571 | ) | | 109,962 |
| | 49,333 |
| | — |
| | — |
| | — |
| | 39,420 |
|
| Pension and other post-employment benefits | | (17,534 | ) | | 158,661 |
| | (7,288 | ) | | (7,504 | ) | | (15,053 | ) | | (1,413 | ) | | (20,420 | ) | | 149,680 |
| | (6,628 | ) | | (8,939 | ) | | (16,703 | ) | | (1,037 | ) |
| Sale and leaseback | | — |
| | 45,136 |
| | — |
| | — |
| | — |
| | 108,172 |
| | — |
| | 37,236 |
| | — |
| | — |
| | — |
| | 102,484 |
|
| Accumulated deferred investment tax credit | | 14,791 |
| | 58,863 |
| | 2,436 |
| | 332 |
| | 5,158 |
| | 18,862 |
| | 14,320 |
| | 56,635 |
| | 1,777 |
| | 290 |
| | 4,842 |
| | 17,385 |
|
| Provision for allowances and contingencies | | (7,149 | ) | | 125,805 |
| | 19,590 |
| | 10,986 |
| | 8,017 |
| | 133 |
| | 1,024 |
| | 123,007 |
| | 18,735 |
| | 33,843 |
| | 7,266 |
| | 134 |
|
| Power purchase agreements | | | (1,279 | ) | | 13,840 |
| | 1,901 |
| | 13 |
| | 575 |
| | — |
|
| Unbilled/deferred revenues | | 12,322 |
| | (25,016 | ) | | 12,956 |
| | 3,395 |
| | 11,573 |
| | — |
| | 9,815 |
| | (32,365 | ) | | 7,154 |
| | 2,126 |
| | 10,851 |
| | — |
|
| Compensation | | 2,085 |
| | 158 |
| | (846 | ) | | 475 |
| | 4,155 |
| | — |
| | 1,842 |
| | 4,182 |
| | 601 |
| | 880 |
| | 4,496 |
| | — |
|
| Net operating loss carryforwards | | 105,063 |
| | 241,803 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 90,241 |
| | — |
| | — |
| | — |
| | — |
|
| Capital losses and miscellaneous tax credits | | — |
| | — |
| | 3,504 |
| | — |
| | — |
| | — |
| |
| Other | | 258 |
| | 15,508 |
| | 5,887 |
| | 2,891 |
| | 3,850 |
| | 2,000 |
| | 128 |
| | 21,982 |
| | 1,995 |
| | 316 |
| | 1,672 |
| | — |
|
| Total | | 212,168 |
| | 948,657 |
| | 43,453 |
| | 40,155 |
| | 21,779 |
| | 155,473 |
| | 133,761 |
| | 728,925 |
| | 33,322 |
| | 49,417 |
| | 20,306 |
| | 173,313 |
|
| Non-current accrued taxes (including unrecognized tax benefits) | | 9,367 |
| | (412,508 | ) | | (12,481 | ) | | (19,502 | ) | | (48,921 | ) | | (81,528 | ) | | (22,978 | ) | | (641,120 | ) | | (402 | ) | | (29,846 | ) | | (40,693 | ) | | (416,996 | ) |
| Accumulated deferred income taxes and taxes accrued | |
| ($1,991,459 | ) | |
| ($2,954,076 | ) | |
| ($795,176 | ) | |
| ($190,679 | ) | |
| ($1,045,949 | ) | |
| ($822,346 | ) | |
| ($1,982,812 | ) | |
| ($2,506,956 | ) | |
| ($810,635 | ) | |
| ($214,061 | ) | |
| ($1,006,834 | ) | |
| ($1,019,075 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ estimated tax attributes carryovers and their expiration dates as of December 31, 20152016 are as follows:
| | | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Federal net operating losses | | $7 million | | $2.4 billion | | — | | — | | — | | $242 million | | $184 million | | $4.4 billion | | — | | $34 million | | — | | $201 million |
| Year(s) of expiration | | 2030-2035 | | 2035 | | N/A | | N/A | | N/A | | 2030-2035 | | 2028-2036 | | 2036 | | N/A | | 2028-2036 | | N/A | | 2028-2036 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| State net operating losses | | — | | $2.5 billion | | — | | $6 million | | — | | $833 million | | $80 million | | $4.8 billion | | — | | $285 million | | — | | $175 million |
| Year(s) of expiration | | N/A | | 2035 | | N/A | | 2032 | | N/A | | 2035 | | 2021 | | 2029-2036 | | N/A | | 2032-2035 | | N/A | | 2035 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| Misc. federal credits | | $1 million | | — | | $1 million | | — | | — | | $1 million | | $2 million | | — | | $3 million | | — | | — | | $2 million |
| Year(s) of expiration | | 2029-2033 | | N/A | | 2029-2034 | | N/A | | N/A | | 2029-2033 | | 2029-2036 | | N/A | | 2029-2036 | | N/A | | N/A | | 2029-2036 |
| | | | | | | | | | | | | | | | | | | | | | | | | |
| State credits | | — | | — | | — | | — | | $3.3 million | | $6 million | | — | | — | | $4.5 million | | — | | $3.4 million | | $8.4 million |
| Year(s) of expiration | | N/A | | N/A | | N/A | | N/A | | 2026 | | 2017-2020 | | N/A | | N/A | | 2018-2020 | | N/A | | 2026 | | 2017-2020 |
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.
Unrecognized tax benefits
Accounting standards establish a “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’s beginning and ending amount of unrecognized tax benefits is as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Gross balance at January 1 |
| $4,736,785 |
| |
| $4,593,224 |
| |
| $4,170,403 |
|
| $2,611,585 |
| |
| $4,736,785 |
| |
| $4,593,224 |
|
| Additions based on tax positions related to the current year | 1,850,705 |
| | 348,543 |
| | 162,338 |
| 1,532,782 |
| | 1,850,705 |
| | 348,543 |
|
| Additions for tax positions of prior years | 59,815 |
| | 11,637 |
| | 410,108 |
| 368,404 |
| | 59,815 |
| | 11,637 |
|
| Reductions for tax positions of prior years (a) | (3,966,535 | ) | | (213,401 | ) | | (103,360 | ) | (265,653 | ) | | (3,966,535 | ) | | (213,401 | ) |
| Settlements | (68,227 | ) | | — |
| | (43,620 | ) | (337,263 | ) | | (68,227 | ) | | — |
|
| Lapse of statute of limitations | (958 | ) | | (3,218 | ) | | (2,645 | ) | — |
| | (958 | ) | | (3,218 | ) |
| Gross balance at December 31 | 2,611,585 |
| | 4,736,785 |
| | 4,593,224 |
| 3,909,855 |
| | 2,611,585 |
| | 4,736,785 |
|
| Offsets to gross unrecognized tax benefits: | |
| | |
| | |
| |
| | |
| | |
|
| Credit and loss carryovers | (1,264,483 | ) | | (4,295,643 | ) | | (4,400,498 | ) | |
| Unrecognized tax benefits net of unused tax attributes and payments (b) |
| $1,347,102 |
| |
| $441,142 |
| |
| $192,726 |
| |
| Carryovers and refund claims | | (2,922,085 | ) | | (1,264,483 | ) | | (4,295,643 | ) |
| Cash paid to taxing authorities | | (10,000 | ) | | — |
| | — |
|
| Unrecognized tax benefits net of unused tax attributes, refund claims and payments (b) | |
| $977,770 |
| |
| $1,347,102 |
| |
| $441,142 |
|
| |
| (a) | The primary reduction for 2015 is related to the nuclear decommissioning costs treatment discussed in “Income Tax Audits - 2008-2009 IRS Audit” below. |
| |
| (b) | Potential tax liability above what is payable on tax returns |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The balances of unrecognized tax benefits include $1,240 million, $955 million, $516 million, and $176$516 million as of December 31, 2016, 2015, 2014, and 2013,2014, 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 $1.657 billion, $4.221 billion,$2,670 million, $1,657 million, and $4.417 billion$4,221 million as of December 31, 2016, 2015, 2014, and 2013,2014, 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 accrues interest expense, if any, related to unrecognized tax benefits in income tax expense. Entergy’s December 31, 2016, 2015, 2014, and 20132014 accrued balance for the possible payment of interest is approximately $30 million, $27 million, $127 million, and $96.4$127 million, respectively.
A reconciliation of the Registrant Subsidiaries’ beginning and ending amount of unrecognized tax benefits for 2016, 2015, 2014, and 20132014 is as follows:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Gross balance at January 1, 2015 | |
| $362,912 |
| |
| $1,205,929 |
| |
| $20,144 |
| |
| $53,763 |
| |
| $17,264 |
| |
| $258,242 |
| |
| Gross balance at January 1, 2016 | | |
| $25,445 |
| |
| $1,690,661 |
| |
| $19,482 |
| |
| $53,897 |
| |
| $13,462 |
| |
| $478,318 |
|
| Additions based on tax positions related to the current year (a) | | 2,196 |
| | 1,367,058 |
| | 566 |
| | 472 |
| | 657 |
| | 472,304 |
| | 16,868 |
| | 931,720 |
| | 2,662 |
| | 33,912 |
| | 2,002 |
| | 5,318 |
|
| Additions for tax positions of prior years | | 1,057 |
| | 7,992 |
| | 8,140 |
| | 48 |
| | 2,914 |
| | 913 |
| | 2,463 |
| | 157,586 |
| | 336 |
| | 129,784 |
| | 2,888 |
| | 601 |
|
| Reductions for tax positions of prior years | | (340,720 | ) | | (859,430 | ) | | — |
| | (386 | ) | | (3,981 | ) | | (253,141 | ) | | (41,957 | ) | | (144,068 | ) | | (10,219 | ) | | (29,821 | ) | | (1,849 | ) | | (10,266 | ) |
| Settlements | | — |
| | (30,888 | ) | | (9,368 | ) | | — |
| | (3,392 | ) | | — |
| | (316 | ) | | (195,560 | ) | | (55 | ) | | (21,542 | ) | | (557 | ) | | (1,599 | ) |
| Gross balance at December 31, 2015 | | 25,445 |
| | 1,690,661 |
| | 19,482 |
| | 53,897 |
| | 13,462 |
| | 478,318 |
| |
| Gross balance at December 31, 2016 | | | 2,503 |
| | 2,440,339 |
| | 12,206 |
| | 166,230 |
| | 15,946 |
| | 472,372 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (3,613 | ) | | (893,764 | ) | | (1,016 | ) | | (506 | ) | | (276 | ) | | (133,611 | ) | | — |
| | (1,783,093 | ) | | (2,373 | ) | | (27,320 | ) | | (376 | ) | | (90,028 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $21,832 |
| |
| $796,897 |
| |
| $18,466 |
| |
| $53,391 |
| |
| $13,186 |
| |
| $344,707 |
| |
| $2,503 |
| |
| $657,246 |
| |
| $9,833 |
| |
| $138,910 |
| |
| $15,570 |
| |
| $382,344 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2015 | |
| $362,912 |
| |
| $1,205,929 |
| |
| $20,144 |
| |
| $53,763 |
| |
| $17,264 |
| |
| $258,242 |
|
| Additions based on tax positions related to the current year (b) | | 2,196 |
| | 1,367,058 |
| | 566 |
| | 472 |
| | 657 |
| | 472,304 |
|
| Additions for tax positions of prior years | | 1,057 |
| | 7,992 |
| | 8,140 |
| | 48 |
| | 2,914 |
| | 913 |
|
| Reductions for tax positions of prior years | | (340,720 | ) | | (859,430 | ) | | — |
| | (386 | ) | | (3,981 | ) | | (253,141 | ) |
| Settlements | | — |
| | (30,888 | ) | | (9,368 | ) | | — |
| | (3,392 | ) | | — |
|
| Gross balance at December 31, 2015 | | 25,445 |
| | 1,690,661 |
| | 19,482 |
| | 53,897 |
| | 13,462 |
| | 478,318 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (3,613 | ) | | (893,764 | ) | | (1,016 | ) | | (506 | ) | | (276 | ) | | (133,611 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $21,832 |
| |
| $796,897 |
| |
| $18,466 |
| |
| $53,391 |
| |
| $13,186 |
| |
| $344,707 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2014 | |
| $347,713 |
| |
| $1,076,680 |
| |
| $16,186 |
| |
| $51,679 |
| |
| $13,017 |
| |
| $265,185 |
|
| Additions based on tax positions related to the current year | | 14,511 |
| | 151,249 |
| | 3,928 |
| | 2,235 |
| | 4,225 |
| | 2,744 |
|
| Additions for tax positions of prior years | | 1,767 |
| | 6,924 |
| | 319 |
| | 37 |
| | 303 |
| | 566 |
|
| Reductions for tax positions of prior years | | (1,079 | ) | | (28,924 | ) | | (289 | ) | | (188 | ) | | (267 | ) | | (10,253 | ) |
| Settlements | | — |
| | — |
| | — |
| | — |
| | (14 | ) | | — |
|
| Gross balance at December 31, 2014 | | 362,912 |
| | 1,205,929 |
| | 20,144 |
| | 53,763 |
| | 17,264 |
| | 258,242 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (361,043 | ) | | (739,988 | ) | | (6,992 | ) | | (20,735 | ) | | (241 | ) | | (163,124 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $1,869 |
| |
| $465,941 |
| |
| $13,152 |
| |
| $33,028 |
| |
| $17,023 |
| |
| $95,118 |
|
| |
| (a) | The primary addition for Entergy Louisiana is related to the mark-to market treatment discussed in “Other Tax Matters” below. |
| |
| (b) | The primary addition for Entergy Louisiana and System Energy is related to the nuclear decommissioning costs treatment discussed in “Other Tax Matters” below. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2014 | |
| $347,713 |
| |
| $1,076,680 |
| |
| $16,186 |
| |
| $51,679 |
| |
| $13,017 |
| |
| $265,185 |
|
| Additions based on tax positions related to the current year | | 14,511 |
| | 151,249 |
| | 3,928 |
| | 2,235 |
| | 4,225 |
| | 2,744 |
|
| Additions for tax positions of prior years | | 1,767 |
| | 6,924 |
| | 319 |
| | 37 |
| | 303 |
| | 566 |
|
| Reductions for tax positions of prior years | | (1,079 | ) | | (28,924 | ) | | (289 | ) | | (188 | ) | | (267 | ) | | (10,253 | ) |
| Settlements | | — |
| | — |
| | — |
| | — |
| | (14 | ) | | — |
|
| Gross balance at December 31, 2014 | | 362,912 |
| | 1,205,929 |
| | 20,144 |
| | 53,763 |
| | 17,264 |
| | 258,242 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (361,043 | ) | | (739,988 | ) | | (6,992 | ) | | (20,735 | ) | | (241 | ) | | (163,124 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $1,869 |
| |
| $465,941 |
| |
| $13,152 |
| |
| $33,028 |
| |
| $17,023 |
| |
| $95,118 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| 2013 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Gross balance at January 1, 2013 | |
| $344,669 |
| |
| $1,002,394 |
| |
| $16,841 |
| |
| $52,018 |
| |
| $13,954 |
| |
| $260,346 |
|
| Additions based on tax positions related to the current year | | 6,427 |
| | 17,887 |
| | 957 |
| | 583 |
| | 2,170 |
| | 4,170 |
|
| Additions for tax positions of prior years | | 1,228 |
| | 125,214 |
| | 401 |
| | 3,506 |
| | 587 |
| | 8,391 |
|
| Reductions for tax positions of prior years | | (3,943 | ) | | (53,473 | ) | | (1,941 | ) | | (962 | ) | | (4,186 | ) | | (967 | ) |
| Settlements | | (668 | ) | | (15,342 | ) | | (72 | ) | | (3,466 | ) | | 492 |
| | (6,755 | ) |
| Gross balance at December 31, 2013 | | 347,713 |
| | 1,076,680 |
| | 16,186 |
| | 51,679 |
| | 13,017 |
| | 265,185 |
|
| Offsets to gross unrecognized tax benefits: | | |
| | |
| | |
| | |
| | |
| | |
|
| Loss carryovers | | (345,674 | ) | | (747,756 | ) | | (16,186 | ) | | (22,078 | ) | | (266 | ) | | (225,286 | ) |
| Unrecognized tax benefits net of unused tax attributes and payments | |
| $2,039 |
| |
| $328,924 |
| |
| $— |
| |
| $29,601 |
| |
| $12,751 |
| |
| $39,899 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ balances of unrecognized tax benefits included amounts which, if recognized, would have reduced income tax expense as follows:
| | | | December 31, | December 31, |
| | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $4.5 |
| |
| $2.6 |
| |
| $0.6 |
|
| $3.6 |
| |
| $4.5 |
| |
| $2.6 |
|
| Entergy Louisiana |
| $692.7 |
| |
| $267.3 |
| |
| $131.9 |
|
| $473.3 |
| |
| $692.7 |
| |
| $267.3 |
|
| Entergy Mississippi |
| $8.1 |
| |
| $3.9 |
| |
| $3.9 |
|
| $— |
| |
| $8.1 |
| |
| $3.9 |
|
| Entergy New Orleans |
| $50.7 |
| |
| $50.7 |
| |
| $— |
|
| $33.6 |
| |
| $50.7 |
| |
| $50.7 |
|
| Entergy Texas |
| $5.2 |
| |
| $10.5 |
| |
| $10.1 |
|
| $7.0 |
| |
| $5.2 |
| |
| $10.5 |
|
| System Energy |
| $0.7 |
| |
| $3.7 |
| |
| $3.3 |
|
| $— |
| |
| $0.7 |
| |
| $3.7 |
|
The Registrant Subsidiaries accrue interest and penalties related to unrecognized tax benefits in income tax expense. Penalties have not been accrued. Accrued balances for the possible payment of interest are as follows:
| | | | December 31, | December 31, |
| | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $1.3 |
| |
| $17.0 |
| |
| $15.2 |
|
| $1.4 |
| |
| $1.3 |
| |
| $17.0 |
|
| Entergy Louisiana |
| $9.3 |
| |
| $22.2 |
| |
| $18.0 |
|
| $8.4 |
| |
| $9.3 |
| |
| $22.2 |
|
| Entergy Mississippi |
| $0.4 |
| |
| $2.8 |
| |
| $2.1 |
|
| $0.8 |
| |
| $0.4 |
| |
| $2.8 |
|
| Entergy New Orleans |
| $1.8 |
| |
| $1.3 |
| |
| $0.9 |
|
| $1.5 |
| |
| $1.8 |
| |
| $1.3 |
|
| Entergy Texas |
| $1.2 |
| |
| $1.0 |
| |
| $0.8 |
|
| $1.2 |
| |
| $1.2 |
| |
| $1.0 |
|
| System Energy |
| $0.7 |
| |
| $23.8 |
| |
| $19.0 |
|
| $3.7 |
| |
| $0.7 |
| |
| $23.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Income Tax Audits
Entergy and its subsidiaries file U.S. federal and various state and foreign income tax returns. IRS examinations are complete for years before 2010.2012. All state taxing authorities’ examinations are completed for years before 2009.
2006-2007 IRS Audit
In the first quarter 2015, the IRS finalized tax and interest computations from the 2006-2007 audit that resulted in a reversal of Entergy’s provision for uncertain tax positions related to accrued interest of approximately $20 million, including decreases of approximately $4 million for Entergy Arkansas, $11 million for Entergy Louisiana, and $1 million for System Energy.
2008-2009 IRS Audit
In the fourth quarter 2009, Entergy filed Applications for Change in Accounting Method (the “2009 CAM”) for tax purposes with the IRS for certain costs under Section 263A of the Internal Revenue Code. In the Applications, Entergy proposed 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 the 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 related to the 2009 CAM. In the third quarter 2013, the Internal Revenue Service issued its RAR for the tax years 2008-2009. As a result of the issuance of this RAR, Entergy and the IRS resolved all of the 2008-2009 issues described above except for the 2009
Entergy Corporation and Subsidiaries
Notes to Financial Statements
CAM. Entergy disagreed with the IRS’s disallowance of the 2009 CAM and filed a protest with the IRS Appeals Division in October 2013.
In August 2015, Entergy and the IRS agreed on the treatment of the 2009 position regarding nuclear decommissioning liabilities from the 2008-2009 audit. The agreement provides that Entergy is entitled to deduct approximately $118 million of the $9.3 billion claimed in 2009. The agreement effectively settled all matters pertaining to the 2009 tax year and increased Entergy’s 2009 federal income tax liability by $2.4 million.
2010-2011 IRS Audit
The IRS completed its examination of the 2010 and 2011 tax years is ongoingand issued its 2010-2011 Revenue Agent Report (RAR) in June 2016. Entergy agreed to all proposed adjustments contained in the RAR. As a result of the issuance of the RAR, Entergy Louisiana was able to recognize previously unrecognized tax benefits as follows:
Entergy and the audit field workIRS agreed that $148.6 million of the proceeds received by Entergy Louisiana in 2010 from the Louisiana Utilities Restoration Corporation (LURC), an instrumentality of the State of Louisiana, for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55) were not taxable. Because the treatment of the financing is expected to be completedsettled, Entergy recognized previously unrecognized tax benefits totaling $63.5 million, of which Entergy Louisiana recorded $61.6 million. Entergy Louisiana also accrued a regulatory liability of $16.1 million ($9.9 million net-of-tax) in accordance with the terms of Entergy Louisiana’s previous settlement agreement approved by the end ofLPSC regarding Entergy Louisiana’s obligation to pay to customers savings associated with the first quarter of 2016. The IRS has not issued any significant notices of proposed adjustments other than for the decommissioning liability position discussed above. The Revenue Agent’s Report is expected to be received shortly after the completion of field work.Act 55 financing.
Entergy and the IRS agreed upon the tax treatment of Entergy Louisiana’s regulatory liability related to the Vidalia purchased power agreement. As a result, Entergy Louisiana recognized a previously unrecognized tax benefit of $74.5 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Tax Matters
Entergy regularly negotiates with the IRS to achieve settlements. The resolution of audit issues could result in significant changes to the amounts of unrecognized tax benefits in the next twelve months.
In September 2013 the U.S. Treasury Department and the IRS issued final regulations that provide guidance on the deductibility and capitalization of costs incurred associated with tangible property. Entergy and the Registrant Subsidiaries filed with the IRS an automatic application for change in accounting method which is in compliance with the final regulations and the safe harbor provisions of the relevant IRS Revenue Procedures. Entergy estimates that the effect of this accounting method change will result in a net increase to Entergy’s taxable income of approximately $585 million, which will be recognized generally over a four year period beginning with the tax year ended 2014. The adoption of the final regulations and safe harbor method results in approximate changes in the Registrant Subsidiaries taxable income as follows: an increase of $177 million for Entergy Arkansas, an increase of $78 million for Entergy Louisiana, an increase of $26 million for Entergy Mississippi, an increase of $183 million for Entergy Texas, a decrease of $2 million for Entergy New Orleans, and an increase of $22 million for System Energy.
In October 2015 two of Entergy’s Louisiana utilities, Entergy Gulf States Louisiana and Entergy Louisiana, combined their businesses into a legal entity which is identified as Entergy Louisiana herein. The structure of the business combination generated both a permanent difference and a temporary difference under FASB ASC Topic 740. The permanent difference resulted from recognition of the Waterford 3 and River Bend decommissioning liabilities as part of the business combination. Recognition of such decommissioning liabilities required Entergy to also recognize a taxable gain. The taxable gain resulted in a temporary difference because the gain provided for an increase in tax basis. Entergy Louisiana maintained a carryover tax basis in the assets received. Additionally, the tax consequences provided for an increase in tax basis as well. Toreceived; and, to the extent that thisthe increase in tax basis will provide additional tax depreciation, Entergy recorded a deferred tax asset and current tax expense resulting in a net increase in tax basis of approximately $334 million andasset. Entergy Louisiana obtained athe corresponding deferred tax asset.asset in the business combination. The permanent tax benefit net of ancillary tax charges was approximately $334 million. Consistent with the terms of an agreement with the LPSC,stipulated settlement in the business combination proceeding, electric customers of Entergy Louisiana will realize customer credits associated with the business combination. Accordingly, in October 2015, Entergy recorded a regulatory liability of $107 million ($66 million net-of-tax) which partially offsets the effect of the aforementioned deferred tax asset. The deferred tax asset and the regulatory liability, net-of-tax, increased Entergy Louisiana’s member’s equity by $268 million. See Note 2 to the financial statements for further discussion of the business combination.
In the fourth quarter 2015, System Energy and Entergy Louisiana adopted a new method of accounting for income tax return purposes in which the companies’ nuclear decommissioning costs will be treated as production costs of electricity includable in cost of goods sold. The new method results in a reduction of taxable income of $1.2 billion for System Energy and $2.2 billion for Entergy Louisiana.
The Protecting Americans from Tax Hikes Act of 2015 was enacted in December 2015. The most significant provisions affecting Entergy and the Registrant Subsidiaries were a five-year extension of bonus depreciation and permanent extension of the research and experimentation tax credit. The effect of the bonus depreciation extension on 2015 increased Entergy’s tax net operating loss.
Entergy made a tax election to treat its subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes in the second quarter 2016. This resulted in a constructive contribution of all the assets and liabilities associated with the plant to a new subsidiary corporation for federal income tax purposes, and generated both permanent and temporary differences under the income tax accounting standards. The constructive contribution required Entergy to recognize the plant’s nuclear decommissioning liability for income tax purposes resulting in permanent differences. The accrual of the nuclear decommissioning liability required Entergy to recognize a gain for income tax purposes, a significant portion of which resulted in an increase in tax basis of the assets constructively contributed to the subsidiary. Recognition of the gain and the increase in tax basis of the assets represents a temporary difference. The permanent difference reduced income tax expense, net of unrecognized tax benefits, by $238 million.
In 2016, Entergy Louisiana elected mark-to-market income tax treatment for various wholesale electric power purchase and sale agreements, including Entergy Louisiana’s contract to purchase electricity from the Vidalia hydroelectric facility and from System Energy under the Unit Power Sales Agreement. The election resulted in a $2.2 billion deductible temporary difference.
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 Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy Corporation has in place a credit facility that has a borrowing capacity of $3.5 billion and expires in August 2020.2021. 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%0.225% of the undrawn 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, 20152016 was 1.98%2.23% 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, 2015.2016.
| | Capacity (a) | | Borrowings | | Letters of Credit | | Capacity Available | | Borrowings | | Letters of Credit | | Capacity Available |
(In Millions) | | $3,500 | | $835 | | $9 | | $2,656 | | $700 | | $6 | | $2,794 |
Entergy Corporation’s credit facility requires itEntergy to maintain a consolidated debt ratio, as defined, 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.
Entergy Corporation has a commercial paper program with a Board-approved program limit of up to $1.5 billion. At December 31, 2015,2016, Entergy Corporation had $422$344 million of commercial paper outstanding. The weighted-average interest rate for the year ended December 31, 20152016 was 0.90%1.13%.
Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each had credit facilities available as of December 31, 20152016 as follows:
|
| | | | | | | | | |
| Company | | Expiration Date | | Amount of Facility | | Interest Rate (a) | | Amount Drawn as of December 31, 2015 2016 | Letters of Credit Outstanding as of December 31, 2015 2016 |
| Entergy Arkansas | | April 20162017 | | $20 million (b) | | 1.92%2.02% | | — | — |
| Entergy Arkansas | | August 20202021 | | $150 million (c) | | 1.92%2.02% | | — | — |
| Entergy Louisiana | | August 20202021 | | $350 million (d) | | 1.67%2.02% | | — | $3.16.4 million |
| Entergy Mississippi | | May 20162017 | | $10 million (e) | | 1.92%2.27% | | — | — |
| Entergy Mississippi | | May 20162017 | | $20 million (e) | | 1.92%2.27% | | — | — |
| Entergy Mississippi | | May 20162017 | | $35 million (e) | | 1.92%2.27% | | — | — |
| Entergy Mississippi | | May 20162017 | | $37.5 million (e) | | 1.92%2.27% | | — | — |
| Entergy New Orleans | | November 2018 | | $25 million (f) | | 2.17%2.52% | | — | —$0.8 million |
| Entergy Texas | | August 20202021 | | $150 million (f)(g) | | 1.92%2.27% | | — | $1.34.7 million |
| |
| (a) | The interest rate is the rate as of December 31, 20152016 that would most likely be applied to outstanding borrowings under the facility. |
| |
| (b) | Borrowings under this Entergy Arkansas credit facility may be secured by a security interest in its accounts receivable at Entergy Arkansas’s option. |
| |
| (c) | The credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. |
| |
| (d) | The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (e) | Borrowings under the Entergy Mississippi credit facilities may be secured by a security interest in its accounts receivable at Entergy Mississippi’s option. |
| |
| (f) | The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility. |
| |
| (g) | The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. |
The commitment fees on the credit facilities range from 0.125%0.075% to 0.275% of the undrawn commitment amount. Each of the credit facilities requires the Registrant Subsidiary borrower to maintain a debt ratio, as defined, of 65% or less of its total capitalization. Each Registrant Subsidiary is in compliance with this covenant.
In addition, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas each entered into one or more uncommitted standby letter of credit facilities as a means to post collateral to support its obligations related to MISO. Following is a summary of the uncommitted standby letter of credit facilities as of December 31, 2015:2016:
|
| | | | | | |
| Company | | Amount of Uncommitted Facility | | Letter of Credit Fee | | Letters of Credit Issued as of December 31, 20152016 (a) |
| Entergy Arkansas | | $25 million | | 0.70% | | $1.0 million |
| Entergy Louisiana | | $125 million | | 0.70% | | $17.15.7 million |
| Entergy Mississippi | | $40 million | | 0.70% | | $6.07.1 million |
| Entergy New Orleans | | $15 million | | 0.75%1.00% | | $1.46.2 million |
| Entergy Texas | | $50 million | | 0.70% | | $9.414.7 million |
| |
| (a) | As of December 31, 2016, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. See Note 15 to the financial statements for discussion of financial transmission rights. |
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, 2017. In addition to borrowings from commercial banks, these companies may also borrow from the Entergy System money pool. The money pool is an inter-company borrowing arrangement designed to reduce the Utility 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. The following are the FERC-authorized limits for short-term borrowings and the outstanding short-term borrowings as of December 31, 20152016 (aggregating both money pool and external short-term borrowings) for the Registrant Subsidiaries:
| | | | Authorized | | Borrowings | Authorized | | Borrowings |
| | (In Millions) | (In Millions) |
| Entergy Arkansas | $250 | | $52.7 | $250 | | $51.2 |
| Entergy Louisiana | $450 | | — | $450 | | — |
| Entergy Mississippi | $175 | | — | $175 | | — |
| Entergy New Orleans | $100 | | — | $100 | | — |
| Entergy Texas | $200 | | $22.1 | $200 | | — |
| System Energy | $200 | | — | $200 | | — |
Entergy Nuclear Vermont Yankee Credit Facilities
In January 2015, Entergy Nuclear Vermont Yankee entered intohas a credit facility guaranteed by Entergy Corporation with a borrowing capacity of $60$100 million which expires in January 2018. Entergy Nuclear Vermont Yankee does not have the ability
Entergy Corporation and Subsidiaries
Notes to Financial Statements
to issue letters of credit against thisthe credit facility. This facility provides working capital to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities.Yankee. The commitment fee is currently 0.25%0.20% of the undrawn commitment amount. As of December 31, 2015, $122016, $45 million wasin cash borrowings were outstanding onunder the credit facility. The weighted average interest rate for the year ended December 31, 20152016 was 2.08%2.17% on the drawn portion of the facility.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Also in January 2015, Entergy Nuclear Vermont Yankee entered intoalso has an uncommitted credit facility guaranteed by Entergy Corporation
with a borrowing capacity of $85 million which expires in January 2018. Entergy Nuclear Vermont Yankee does not have the ability to issue letters of credit against thisthe credit facility. This facility provides an additional funding source to Entergy Nuclear Vermont Yankee for general business purposes including, without limitation, the decommissioning of Entergy Nuclear Vermont Yankee’s nuclear facilities.Yankee. As of December 31, 2015,2016, there were no amounts werecash borrowings outstanding under the credit facility. The rate as of December 31, 20152016 that would most likely apply to outstanding borrowings under the facility was 2.17%2.27% on the drawn portion of the facility.
Variable Interest Entities (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
See Note 1817 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 toTo finance the acquisition and ownership of nuclear fuel, as followsthe nuclear fuel company VIEs have credit facilities and three of the four VIEs also issue commercial paper, details of which follow as of December 31, 2015:2016:
| | Company | | Expiration Date | | Amount of Facility | | Weighted Average Interest Rate on Borrowings (a) | | Amount Outstanding as of December 31, 2015 | | Expiration Date | | Amount of Facility | | Weighted Average Interest Rate on Borrowings (a) | | Amount Outstanding as of December 31, 2016 |
| | | (Dollars in Millions) | | (Dollars in Millions) |
| Entergy Arkansas VIE | | June 2016 | | $85 | | 1.98% | | $11.7 | | May 2019 | | $80 | | n/a | |
| $— |
|
| Entergy Louisiana River Bend VIE | | June 2016 | | $100 | | 1.38% | | $0.6 | | May 2019 | | $105 | | n/a | |
| $— |
|
| Entergy Louisiana Waterford VIE | | June 2016 | | $90 | | 1.59% | | $60.4 | | May 2019 | | $85 | | 2.15% | |
| $3.8 | (b) |
| System Energy VIE | | June 2016 | | $125 | | n/a | | $— | | May 2019 | | $120 | | 2.20% | |
| $66.9 | (b) |
| |
| (a) | Includes 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 Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.
Amounts outstanding on the Entergy Louisiana River Bend variable interest entity’s credit facility, if any, are included in debt on Entergy’s balance sheet and commercial paper outstanding for the other nuclear fuel company variable interest entities isentity for Entergy Louisiana River Bend does not issue commercial paper, but borrows directly on its bank credit facility.
(b) Commercial paper, classified as a current liability on the respective balance sheets. liability.
The commitment fees on the credit facilities are currently 0.10% of the undrawn commitment amount for the Entergy Louisiana VIEs and 0.125% of the undrawn commitment amount for theArkansas, Entergy ArkansasLouisiana, and System Energy VIEs. Each credit facility requires the respective lessee of nuclear fuel (Entergy Arkansas, Entergy Louisiana, or Entergy Corporation as guarantor for System Energy) to maintain a consolidated debt ratio, as defined, of 70% or less of its total capitalization.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The nuclear fuel company variable interest entities had notes payable that are included in debt on the respective balance sheets as of December 31, 20152016 as follows:
|
| | | | | | |
| Company | | Description | | Amount |
| 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 Arkansas VIE | | 3.65% Series L due July 2021 | |
| $90 | million |
| Entergy Arkansas VIE | | 3.17% Series M due December 2023 | |
| $40 | million |
| Entergy Louisiana River Bend VIE | | 3.25% Series Q due July 2017 | |
| $75 | million |
| Entergy Louisiana River Bend VIE | | 3.38% Series R due August 2020 | | $70 million |
Entergy Louisiana Waterford VIE | | 3.30% Series F due March 2016 |
| $2070 | million |
| Entergy Louisiana Waterford VIE | | 3.25% Series G due July 2017 | |
| $25 | million |
| Entergy Louisiana Waterford VIE | | 3.92% Series H due February 2021 | |
| $40 | million |
| Entergy Louisiana Waterford VIE | | 3.22% Series I due December 2023 | |
| $20 | million |
| System Energy VIE | | 4.02% Series H due February 2017 | |
| $50 | million |
| System Energy VIE | | 3.78% Series I due October 2018 | |
| $85 | million |
In February 2017 the System Energy nuclear fuel company variable interest entity redeemed, at maturity, its $50 million of 4.02% Series H notes.
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.
Entergy Arkansas, Entergy Louisiana, and System Energy each have obtained long-term financing authorizations from the FERC that extend through October 2017 for issuances by its nuclear fuel company variable interest entities.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 5. LONG - TERM DEBT (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Long-term debt for Entergy Corporation and subsidiaries as of December 31, 20152016 and 20142015 consisted of:
| |
Type of Debt and Maturity | | Weighted Average Interest Rate December 31, 2015 | | Interest Rate Ranges at December 31, | | Outstanding at December 31, | | Weighted Average Interest Rate December 31, 2016 | | Interest Rate Ranges at December 31, | | Outstanding at December 31, |
| 2015 | | 2014 | | 2015 | | 2014 | 2016 | | 2015 | | 2016 | | 2015 |
| | | | | | | | | (In Thousands) | | | | | | | | (In Thousands) |
| Mortgage Bonds | | | | | | | | | | | | | | | | | | | | |
| 2015-2020 | | 5.96% | | 3.25%-7.125% | | 3.25%-7.125% | |
| $1,725,000 |
| |
| $1,925,000 |
| |
| 2021-2025 | | 4.24% | | 3.05%-5.66% | | 3.05%-5.66% | | 3,683,276 |
| | 3,683,303 |
| |
| 2026-2030 | | 4.65% | | 4.44%-5.65% | | 4.44%-5.65% | | 287,827 |
| | 287,859 |
| |
| 2031-2040 | | 6.04% | | 5.75%-6.38% | | 5.75%-6.38% | | 1,083,000 |
| | 1,115,000 |
| |
| 2041-2064 | | 5.16% | | 4.70%-6.00% | | 4.70%-6.00% | | 2,010,000 |
| | 1,760,000 |
| |
| 2016-2021 | | | 4.92% | | 2.55%-7.125% | | 3.25%-7.125% | |
| $2,350,000 |
| |
| $2,350,000 |
|
| 2022-2026 | | | 3.85% | | 2.40%-5.59% | | 3.05%-5.66% | | 3,965,000 |
| | 3,308,276 |
|
| 2028-2041 | | | 3.06% | | 2.85%-3.25% | | 5.65%-6.38% | | 1,125,000 |
| | 1,270,827 |
|
| 2044-2066 | | | 5.00% | | 4.70%-5.625% | | 4.70%-6.00% | | 2,960,000 |
| | 1,860,000 |
|
| Governmental Bonds (a) | | | | | | | | | | | | | | | | | | | | |
| 2015-2021 | | 2.13% | | 1.55%-2.375% | | 1.55%-2.875% | | 99,700 |
| | 131,655 |
| |
| 2017-2021 | | | 2.22% | | 1.55%-2.375% | | 1.55%-2.375% | | 99,700 |
| | 99,700 |
|
| 2022-2030 | | 5.21% | | 4.90%-5.875% | | 4.90%-5.875% | | 384,680 |
| | 444,680 |
| | 3.98% | | 3.375%-5.875% | | 4.90%-5.875% | | 332,680 |
| | 384,680 |
|
| Securitization Bonds | | | | | | | | | | | | | | | | | | | | |
| 2016-2024 | | 3.83% | | 2.04%-5.93% | | 2.04%-5.93% | | 784,340 |
| | 785,059 |
| |
| 2018-2024 | | | 3.90% | | 2.04%-5.93% | | 2.04%-5.93% | | 669,310 |
| | 784,340 |
|
| Variable Interest Entities Notes Payable (Note 4) | | | | | | | | | | | | | | | | |
| 2016-2021 | | 3.54% | | 1.38%-4.02% | | 2.62%-5.33% | | 570,600 |
| | 630,000 |
| |
| 2016-2023 | | | 3.47% | | 2.62%-4.02% | | 1.38%-4.02% | | 555,000 |
| | 570,600 |
|
| Entergy Corporation Notes | | | | | | | | | | | | | | | | | | | | |
| due September 2015 | | n/a | | — | | 3.625% | | — |
| | 550,000 |
| |
| due January 2017 | | n/a | | 4.70% | | 4.70% | | 500,000 |
| | 500,000 |
| | n/a | | — | | 4.70% | | — |
| | 500,000 |
|
| due September 2020 | | n/a | | 5.125% | | 5.125% | | 450,000 |
| | 450,000 |
| | n/a | | 5.125% | | 5.125% | | 450,000 |
| | 450,000 |
|
| due July 2022 | | n/a | | 4.00% | | — | | 650,000 |
| | — |
| | n/a | | 4.00% | | 4.00% | | 650,000 |
| | 650,000 |
|
| due September 2026 | | | n/a | | 2.95% | | — | | 750,000 |
| | — |
|
| Note Payable to NYPA | | (b) | | (b) | | (b) | | 34,259 |
| | 79,638 |
| | — | | — | | (b) | | — |
| | 34,259 |
|
| 5 Year Credit Facility (Note 4) | | n/a | | 1.98% | | 1.93% | | 835,000 |
| | 695,000 |
| | n/a | | 2.23% | | 1.98% | | 700,000 |
| | 835,000 |
|
| Long-term DOE Obligation (c) | | — | | — | | — | | 181,378 |
| | 181,329 |
| | — | | — | | — | | 181,853 |
| | 181,378 |
|
| Waterford 3 Lease Obligation (d) | | n/a | | 7.45% | | 7.45% | | 108,965 |
| | 128,488 |
| | n/a | | 8.09% | | 7.45% | | 57,492 |
| | 108,965 |
|
| Waterford Series Collateral Trust Mortgage Notes due 2017 (d) | | | n/a | | (e) | | — | | 42,703 |
| | — |
|
| Grand Gulf Lease Obligation (d) | | n/a | | 5.13% | | 5.13% | | 34,361 |
| | 50,671 |
| | n/a | | 5.13% | | 5.13% | | 34,359 |
| | 34,361 |
|
| Vermont Yankee Credit Facility (Note 4) | | n/a | | 2.08% | | — | | 12,000 |
| | — |
| | n/a | | 2.17% | | 2.08% | | 44,500 |
| | 12,000 |
|
| Unamortized Premium and Discount - Net | | | | | | (12,067 | ) | | (12,529 | ) | | | | | | (19,397 | ) | | (12,067 | ) |
| Unamortized Debt Issuance Costs | | (110,349 | ) | | (113,399 | ) | | (128,849 | ) | | (110,349 | ) |
| Other | | | | | | | | 13,960 |
| | 14,331 |
| | | | | | | | 13,204 |
| | 13,960 |
|
| Total Long-Term Debt | | | | | | | | 13,325,930 |
| | 13,286,085 |
| | | | | | | | 14,832,555 |
| | 13,325,930 |
|
| Less Amount Due Within One Year | | | | | | 214,374 |
| | 899,375 |
| | | | | | 364,900 |
| | 214,374 |
|
| Long-Term Debt Excluding Amount Due Within One Year | | | |
| $13,111,556 |
| |
| $12,386,710 |
| | | |
| $14,467,655 |
| |
| $13,111,556 |
|
Fair Value of Long-Term Debt (e)(f) | | | |
| $13,578,511 |
| |
| $13,607,242 |
| | | |
| $14,815,535 |
| |
| $13,578,511 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds, some of which are secured by collateral first mortgage bonds. |
| |
| (b) | These notes do not have a stated interest rate, but have an implicit interest rate of 4.8%. |
| |
| (c) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’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 to the financial statements for further discussion of the Waterford 3 lease obligation and Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets and for further discussion of the Grand Gulf lease obligations.obligation. |
| |
| (e) | This note does not have a stated interest rate, but has an implicit interest rate of 7.458%. |
| |
| (f) | The fair value excludes lease obligations of $109$57 million at Entergy Louisiana and $34 million at System Energy, and long-term DOE obligations of $181$182 million at Entergy Arkansas, and the note payable to NYPA of $35 million at Entergy, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 1615 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades. |
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2015,2016, for the next five years are as follows:
| | | | Amount | Amount |
| | (In Thousands) | (In Thousands) |
| 2016 |
| $204,079 |
| |
| 2017 |
| $766,451 |
|
| $307,403 |
|
| 2018 |
| $822,690 |
|
| $828,084 |
|
| 2019 |
| $768,588 |
|
| $724,899 |
|
| 2020 |
| $1,631,181 |
|
| $795,000 |
|
| 2021 | |
| $1,674,548 |
|
In November 2000, Entergy’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 becoming liable to NYPA for an additional $10 million per year for 10 years, beginning in September 2003. This liability was recorded upon the purchase of Indian Point 2 in September 2001. As part of the purchase agreement with NYPA, Entergy recorded a liability representing the net present value of the payments Entergy would be liable to NYPA for each year that the FitzPatrick and Indian Point 3 power plants would run beyond their respective original NRC license expiration date. With theIn October 2015, Entergy announced a planned shutdown of FitzPatrick at the end of its current fuel cycle,cycle. As a result of the announcement, Entergy reduced this liability by $26.4 million in 2015 pursuant to the terms of the purchase agreement. UnderIn August 2016, Entergy entered into a provision in a letter of credit supporting these notes, if certaintrust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. As part of the Utility operating companies or System Energytrust transfer agreement, the original decommissioning agreements were amended, and the Entergy subsidiaries’ obligation to default on other indebtedness,make additional license extension payments to NYPA was eliminated. In the third quarter 2016, Entergy could be required to post collateral to supportremoved the letternote payable of credit.$35.1 million from the consolidated balance sheet.
Entergy Louisiana, Entergy Mississippi, Entergy Texas, and System Energy have obtained long-term financing authorizations from the FERC that extend through October 2017. Entergy Arkansas has obtained long-term financing authorization from the APSC that extends through December 2018. Entergy New Orleans has obtained long-term financing authorization from the City Council that extends through July 2016.June 2018.
Capital Funds Agreement
Pursuant to an agreement with certain creditors, Entergy Corporation has agreed to supply System Energy with sufficient capital to:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
maintain System Energy’s equity capital at a minimum of 35% of its total capitalization (excluding short-term debt);
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 supplementsa supplement to the agreement assigning System Energy’s rights in the agreement as security for the specific debt.
Long-term debt for the Registrant Subsidiaries as of December 31, 20152016 and 20142015 consisted of:
| | | | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| Entergy Arkansas | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 3.75% Series due February 2021 | |
| $350,000 |
| |
| $350,000 |
| |
| $350,000 |
| |
| $350,000 |
|
| 3.05% Series due June 2023 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 3.7% Series due June 2024 | | 375,000 |
| | 375,000 |
| | 375,000 |
| | 375,000 |
|
| 5.66% Series due February 2025 | | 175,000 |
| | 175,000 |
| | — |
| | 175,000 |
|
| 3.5% Series due April 2026 | | | 380,000 |
| | — |
|
| 5.9% Series due June 2033 | | 100,000 |
| | 100,000 |
| | — |
| | 100,000 |
|
| 6.38% Series due November 2034 | | 60,000 |
| | 60,000 |
| | — |
| | 60,000 |
|
| 5.75% Series due November 2040 | | 225,000 |
| | 225,000 |
| | — |
| | 225,000 |
|
| 4.95% Series due December 2044 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 4.9% Series due December 2052 | | 200,000 |
| | 200,000 |
| | 200,000 |
| | 200,000 |
|
| 4.75% Series due June 2063 | | 125,000 |
| | 125,000 |
| | 125,000 |
| | 125,000 |
|
| 4.875% Series due September 2066 | | | 410,000 |
| | — |
|
| Total mortgage bonds | | 2,110,000 |
| | 2,110,000 |
| | 2,340,000 |
| | 2,110,000 |
|
| Governmental Bonds (a): | | | | | | | | |
| 1.55% Series due 2017, Jefferson County (d) | | 54,700 |
| | 54,700 |
| | 54,700 |
| | 54,700 |
|
| 2.375% Series due 2021, Independence County (d) | | 45,000 |
| | 45,000 |
| | 45,000 |
| | 45,000 |
|
| Total governmental bonds | | 99,700 |
| | 99,700 |
| | 99,700 |
| | 99,700 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | | | | | |
| 3.23% Series J due July 2016 | | 55,000 |
| | 55,000 |
| | — |
| | 55,000 |
|
| 2.62% Series K due December 2017 | | 60,000 |
| | 60,000 |
| | 60,000 |
| | 60,000 |
|
| 3.65% Series L due July 2021 | | 90,000 |
| | 90,000 |
| | 90,000 |
| | 90,000 |
|
| 3.17% Series M due December 2023 | | | 40,000 |
| | — |
|
| Total variable interest entity notes payable | | 205,000 |
| | 205,000 |
| | 190,000 |
| | 205,000 |
|
| Securitization Bonds: | | | | | | | | |
| 2.30% Series Senior Secured due August 2021 | | 62,966 |
| | 76,185 |
| | 49,548 |
| | 62,966 |
|
| Total securitization bonds | | 62,966 |
| | 76,185 |
| | 49,548 |
| | 62,966 |
|
| Other: | | | | | | | | |
| Long-term DOE Obligation (b) | | 181,378 |
| | 181,329 |
| | 181,853 |
| | 181,378 |
|
| Unamortized Premium and Discount – Net | | (2,775 | ) | | (2,960 | ) | | 984 |
| | (2,775 | ) |
| Unamortized Debt Issuance Costs | | (28,503 | ) | | (30,270 | ) | | (34,357 | ) | | (28,503 | ) |
| Other | | 2,073 |
| | 2,089 |
| | 2,057 |
| | 2,073 |
|
| Total Long-Term Debt | | 2,629,839 |
| | 2,641,073 |
| | 2,829,785 |
| | 2,629,839 |
|
| Less Amount Due Within One Year | | 55,000 |
| | — |
| | 114,700 |
| | 55,000 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $2,574,839 |
| |
| $2,641,073 |
| |
| $2,715,085 |
| |
| $2,574,839 |
|
| Fair Value of Long-Term Debt (c) | |
| $2,498,108 |
| |
| $2,517,633 |
| |
| $2,623,910 |
| |
| $2,498,108 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| Entergy Louisiana | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 6.0% Series due May 2018 | | |
| $375,000 |
| |
| $375,000 |
|
| 6.50% Series due September 2018 | |
| $300,000 |
| |
| $300,000 |
| | 300,000 |
| | 300,000 |
|
| 6.0% Series due May 2018 | | 375,000 |
| | 375,000 |
| |
| 3.95% Series due October 2020 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 4.8% Series due May 2021 | | 200,000 |
| | 200,000 |
| | 200,000 |
| | 200,000 |
|
| 3.3% Series due December 2022 | | 200,000 |
| | 200,000 |
| | 200,000 |
| | 200,000 |
|
| 4.05% Series due September 2023 | | 325,000 |
| | 325,000 |
| | 325,000 |
| | 325,000 |
|
| 5.59% Series due October 2024 | | 300,000 |
| | 300,000 |
| | 300,000 |
| | 300,000 |
|
| 5.40% Series due November 2024 | | 400,000 |
| | 400,000 |
| | 400,000 |
| | 400,000 |
|
| 3.78% Series due April 2025 | | 110,000 |
| | 110,000 |
| | 110,000 |
| | 110,000 |
|
| 3.78% Series due April 2025 | | 190,000 |
| | 190,000 |
| | 190,000 |
| | 190,000 |
|
| 4.44% Series due January 2026 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 2.40% Series due October 2026 | | | 400,000 |
| | — |
|
| 3.25% Series due April 2028 | | | 425,000 |
| | — |
|
| 3.05% Series due June 2031 | | | 325,000 |
| | — |
|
| 6.2% Series due July 2033 | | 240,000 |
| | 240,000 |
| | — |
| | 240,000 |
|
| 6.18% Series due March 2035 | | 85,000 |
| | 85,000 |
| | — |
| | 85,000 |
|
| 6.0% Series due March 2040 | | 118,000 |
| | 150,000 |
| | — |
| | 118,000 |
|
| 5.875% Series due June 2041 | | 150,000 |
| | 150,000 |
| | — |
| | 150,000 |
|
| 5.0% Series due July 2044 | | 170,000 |
| | 170,000 |
| | 170,000 |
| | 170,000 |
|
| 4.95% Series due January 2045 | | 250,000 |
| | 250,000 |
| | 450,000 |
| | 250,000 |
|
| 5.25% Series due July 2052 | | 200,000 |
| | 200,000 |
| | 200,000 |
| | 200,000 |
|
| 4.7% Series due June 2063 | | 100,000 |
| | 100,000 |
| |
| 4.70% Series due June 2063 | | | 100,000 |
| | 100,000 |
|
| 4.875% Series due September 2066 | | | 270,000 |
| | — |
|
| Total mortgage bonds | | 4,213,000 |
| | 4,245,000 |
| | 5,240,000 |
| | 4,213,000 |
|
| Governmental Bonds (a): | | | | | | | | |
| 2.875% Series due 2015, Louisiana Public Facilities Authority (d) | | — |
| | 31,955 |
| |
| 5.0% Series due 2028, Louisiana Public Facilities Authority (d) | | 83,680 |
| | 83,680 |
| | — |
| | 83,680 |
|
| 5.0% Series due 2030, Louisiana Public Facilities Authority (d) | | 115,000 |
| | 115,000 |
| | — |
| | 115,000 |
|
| 3.375 % Series due 2028, Louisiana Public Facilities Authority (d) | | | 83,680 |
| | — |
|
| 3.50% Series due 2030, Louisiana Public Facilities Authority (d) | | | 115,000 |
| | — |
|
| Total governmental bonds | | 198,680 |
| | 230,635 |
| | 198,680 |
| | 198,680 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | | | | | |
| 3.30% Series F due March 2016 | | 20,000 |
| | 20,000 |
| | — |
| | 20,000 |
|
| 3.25% Series G due July 2017 | | 25,000 |
| | 25,000 |
| | 25,000 |
| | 25,000 |
|
| 3.25% Series Q due July 2017 | | 75,000 |
| | 75,000 |
| | 75,000 |
| | 75,000 |
|
| 3.38% Series R due August 2020 | | 70,000 |
| | 70,000 |
| | 70,000 |
| | 70,000 |
|
| 3.92% Series H due February 2021 | | 40,000 |
| | 40,000 |
| | 40,000 |
| | 40,000 |
|
| 3.22% Series I due December 2023 | | | 20,000 |
| | — |
|
| Credit Facility due June 2016, weighted avg rate 1.38% | | 600 |
| | — |
| | — |
| | 600 |
|
| Total variable interest entity notes payable | | 230,600 |
| | 230,000 |
| | 230,000 |
| | 230,600 |
|
| Securitization Bonds: | | | | | | | | |
| 2.04% Series Senior Secured due June 2021 | | 122,568 |
| | 143,064 |
| |
| 2.04% Series Senior Secured due September 2023 | | | 100,972 |
| | 122,568 |
|
| Total securitization bonds | | 122,568 |
| | 143,064 |
| | 100,972 |
| | 122,568 |
|
| Other: | | | | | | | | |
| Waterford 3 Lease Obligation 7.45% (Note 10) | | 108,965 |
| | 128,488 |
| |
| Waterford 3 Lease Obligation (Note 10) (e) | | | 57,492 |
| | 108,965 |
|
| Waterford Series Collateral Trust Mortgage Notes due 2017 (Note 10) (f) | | | 42,703 |
| | — |
|
| Unamortized Premium and Discount - Net | | (4,537 | ) | | (5,141 | ) | | (14,917 | ) | | (4,537 | ) |
| Unamortized Debt Issuance Costs | | (40,156 | ) | | (45,103 | ) | | (48,972 | ) | | (40,156 | ) |
| Other | | 7,042 |
| | 7,350 |
| | 6,833 |
| | 7,042 |
|
| Total Long-Term Debt | | 4,836,162 |
| | 4,934,293 |
| | 5,812,791 |
| | 4,836,162 |
|
| Less Amount Due Within One Year | | 29,372 |
| | 51,480 |
| | 200,198 |
| | 29,372 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $5,612,593 |
| |
| $4,806,790 |
|
| Fair Value of Long-Term Debt (c) | |
| $5,018,786 |
| |
| $5,190,547 |
| |
| $5,929,488 |
| |
| $5,018,786 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| Entergy Mississippi | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 3.25% Series due June 2016 | |
| $125,000 |
| |
| $125,000 |
| |
| $— |
| |
| $125,000 |
|
| 6.64% Series due July 2019 | | 150,000 |
| | 150,000 |
| | 150,000 |
| | 150,000 |
|
| 3.1% Series due July 2023 | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
|
| 3.75% Series due July 2024 | | 100,000 |
| | 100,000 |
| | 100,000 |
| | 100,000 |
|
| 2.85% Series due June 2028 | | | 375,000 |
| | — |
|
| 6.0% Series due November 2032 | | 75,000 |
| | 75,000 |
| | — |
| | 75,000 |
|
| 6.25% Series due April 2034 | | 100,000 |
| | 100,000 |
| | — |
| | 100,000 |
|
| 6.20% Series due April 2040 | | 80,000 |
| | 80,000 |
| | — |
| | 80,000 |
|
| 6.0% Series due May 2051 | | 150,000 |
| | 150,000 |
| | — |
| | 150,000 |
|
| 4.90% Series due October 2066 | | | 260,000 |
| | — |
|
| Total mortgage bonds | | 1,030,000 |
| | 1,030,000 |
| | 1,135,000 |
| | 1,030,000 |
|
| Governmental Bonds (a): | | | | | | | | |
| 4.90% Series due 2022, Independence County (d) | | 30,000 |
| | 30,000 |
| | — |
| | 30,000 |
|
| Total governmental bonds | | 30,000 |
| | 30,000 |
| | — |
| | 30,000 |
|
| Other: | | | | | | | | |
| Unamortized Premium and Discount – Net | | (1,038 | ) | | (1,162 | ) | | (766 | ) | | (1,038 | ) |
Unamortized Debt Issuance Costs
| | (13,877 | ) | | (14,979 | ) | | (13,318 | ) | | (13,877 | ) |
| Total Long-Term Debt | | 1,045,085 |
| | 1,043,859 |
| | 1,120,916 |
| | 1,045,085 |
|
| Less Amount Due Within One Year | | 125,000 |
| | — |
| | — |
| | 125,000 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $920,085 |
| |
| $1,043,859 |
| |
| $1,120,916 |
| |
| $920,085 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,087,326 |
| |
| $1,102,741 |
| |
| $1,086,203 |
| |
| $1,087,326 |
|
| | | | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| Entergy New Orleans | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 5.10% Series due December 2020 | |
| $25,000 |
| |
| $25,000 |
| |
| $25,000 |
| |
| $25,000 |
|
| 3.9% Series due July 2023 | | 100,000 |
| | 100,000 |
| | 100,000 |
| | 100,000 |
|
| 5.6% Series due September 2024 | | 33,276 |
| | 33,303 |
| | — |
| | 33,276 |
|
| 4.0% Series due June 2026 | | | 85,000 |
| | — |
|
| 5.65% Series due September 2029 | | 37,827 |
| | 37,859 |
| | — |
| | 37,827 |
|
| 5.0% Series due December 2052 | | 30,000 |
| | 30,000 |
| | 30,000 |
| | 30,000 |
|
| 5.50% Series due April 2066 | | | 110,000 |
| | — |
|
| Total mortgage bonds | | 226,103 |
| | 226,162 |
| | 350,000 |
| | 226,103 |
|
| Securitization Bonds: | | | | | | | | |
| 2.67% Series Senior Secured due June 2024 | | 98,730 |
| | — |
| |
| 2.67% Series Senior Secured due June 2027 | | | 87,307 |
| | 98,730 |
|
| Total securitization bonds | | 98,730 |
|
| — |
| | 87,307 |
|
| 98,730 |
|
| Other: | | | | | | | | |
| Payable to Entergy Louisiana due November 2035 | | 25,500 |
| | 82,316 |
| | 20,527 |
| | 25,500 |
|
| Unamortized Premium and Discount – Net | | (283 | ) | | (296 | ) | | (245 | ) | | (283 | ) |
Unamortized Debt Issuance Costs
| | (7,170 | ) | | (4,682 | ) | | (8,595 | ) | | (7,170 | ) |
| Total Long-Term Debt | | 342,880 |
| | 303,500 |
| | 448,994 |
| | 342,880 |
|
| Less Amount Due Within One Year | | 4,973 |
| | — |
| | 2,104 |
| | 4,973 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $337,907 |
| |
| $303,500 |
| |
| $446,890 |
| |
| $337,907 |
|
| Fair Value of Long-Term Debt (c) | |
| $351,040 |
| |
| $308,665 |
| |
| $455,459 |
| |
| $351,040 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| Entergy Texas | | | | | | | | |
| Mortgage Bonds: | | | | | | | | |
| 3.60% Series due June 2015 | |
| $— |
| |
| $200,000 |
| |
| 7.125% Series due February 2019 | | 500,000 |
| | 500,000 |
| |
| $500,000 |
| |
| $500,000 |
|
| 2.55% Series due June 2021 | | | 125,000 |
| | — |
|
| 4.1% Series due September 2021 | | 75,000 |
| | 75,000 |
| | 75,000 |
| | 75,000 |
|
| 5.15% Series due June 2045 | | 250,000 |
| | — |
| | 250,000 |
| | 250,000 |
|
| 5.625% Series due June 2064 | | 135,000 |
| | 135,000 |
| | 135,000 |
| | 135,000 |
|
| Total mortgage bonds | | 960,000 |
| | 910,000 |
| | 1,085,000 |
| | 960,000 |
|
| Securitization Bonds: | | | | | | | | |
| 2.12% Series Senior Secured, Series A due February 2016 | | — |
| | 13,816 |
| |
| 5.79% Series Senior Secured, Series A due October 2018 | | 49,614 |
| | 74,194 |
| | 23,584 |
| | 49,614 |
|
| 3.65% Series Senior Secured, Series A due August 2019 | | 117,462 |
| | 144,800 |
| | 74,899 |
| | 117,462 |
|
| 5.93% Series Senior Secured, Series A due June 2022 | | 114,400 |
| | 114,400 |
| | 114,400 |
| | 114,400 |
|
| 4.38% Series Senior Secured, Series A due November 2023 | | 218,600 |
| | 218,600 |
| | 218,600 |
| | 218,600 |
|
| Total securitization bonds | | 500,076 |
| | 565,810 |
| | 431,483 |
| | 500,076 |
|
| Other: | | | | | | | | |
| Unamortized Premium and Discount - Net | | (1,797 | ) | | (1,769 | ) | | (1,579 | ) | | (1,797 | ) |
Unamortized Debt Issuance Costs
| | (11,155 | ) | | (10,096 | ) | | (10,809 | ) | | (11,155 | ) |
| Other | | 4,843 |
| | 4,890 |
| | 4,312 |
| | 4,843 |
|
| Total Long-Term Debt | | 1,451,967 |
| | 1,468,835 |
| | 1,508,407 |
| | 1,451,967 |
|
| Less Amount Due Within One Year | | — |
| | 200,000 |
| | — |
| | — |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $1,451,967 |
| |
| $1,268,835 |
| |
| $1,508,407 |
| |
| $1,451,967 |
|
| Fair Value of Long-Term Debt (c) | |
| $1,590,616 |
| |
| $1,629,124 |
| |
| $1,600,156 |
| |
| $1,590,616 |
|
|
| | | | | | | | |
| | | 2016 | | 2015 |
| | | (In Thousands) |
| System Energy | | | | |
| Mortgage Bonds: | | | | |
| 4.1% Series due April 2023 | |
| $250,000 |
| |
| $250,000 |
|
| Total mortgage bonds | | 250,000 |
| | 250,000 |
|
| Governmental Bonds (a): | | | | |
| 5.875% Series due 2022, Mississippi Business Finance Corp. | | 134,000 |
| | 156,000 |
|
| Total governmental bonds | | 134,000 |
| | 156,000 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | |
| 4.02% Series H due February 2017 | | 50,000 |
| | 50,000 |
|
| 3.78% Series I due October 2018 | | 85,000 |
| | 85,000 |
|
| Total variable interest entity notes payable | | 135,000 |
| | 135,000 |
|
| Other: | | | | |
| Grand Gulf Lease Obligation 5.13% (Note 10) | | 34,359 |
| | 34,361 |
|
| Unamortized Premium and Discount – Net | | (503 | ) | | (634 | ) |
| Unamortized Debt Issuance Costs | | (1,727 | ) | | (2,062 | ) |
| Other | | 3 |
| | 2 |
|
| Total Long-Term Debt | | 551,132 |
| | 572,667 |
|
| Less Amount Due Within One Year | | 50,003 |
| | 2 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $501,129 |
| |
| $572,665 |
|
| Fair Value of Long-Term Debt (c) | |
| $529,520 |
| |
| $552,762 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | |
| | | 2015 | | 2014 |
| | | (In Thousands) |
| System Energy | | | | |
| Mortgage Bonds: | | | | |
| 4.1% Series due April 2023 | |
| $250,000 |
| |
| $250,000 |
|
| Total mortgage bonds | | 250,000 |
| | 250,000 |
|
| Governmental Bonds (a): | | | | |
| 5.875% Series due 2022, Mississippi Business Finance Corp. | | 156,000 |
| | 216,000 |
|
| Total governmental bonds | | 156,000 |
| | 216,000 |
|
| Variable Interest Entity Notes Payable (Note 4): | | | | |
| 5.33% Series G due April 2015 | | — |
| | 60,000 |
|
| 4.02% Series H due February 2017 | | 50,000 |
| | 50,000 |
|
| 3.78% Series I due October 2018 | | 85,000 |
| | 85,000 |
|
| Total variable interest entity notes payable | | 135,000 |
| | 195,000 |
|
| Other: | | | | |
| Grand Gulf Lease Obligation 5.13% (Note 10) | | 34,361 |
| | 50,671 |
|
| Unamortized Premium and Discount – Net | | (634 | ) | | (867 | ) |
| Unamortized Debt Issuance Costs | | (2,062 | ) | | (3,893 | ) |
| Other | | 2 |
| | 2 |
|
| Total Long-Term Debt | | 572,667 |
| | 706,913 |
|
| Less Amount Due Within One Year | | 2 |
| | 76,310 |
|
| Long-Term Debt Excluding Amount Due Within One Year | |
| $572,665 |
| |
| $630,603 |
|
| Fair Value of Long-Term Debt (c) | |
| $552,762 |
| |
| $677,475 |
|
| |
| (a) | Consists of pollution control revenue bonds and environmental revenue bonds. |
| |
| (b) | Pursuant to the Nuclear Waste Policy Act of 1982, Entergy’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. |
| |
| (c) | The fair value excludes lease obligations of $109$57 million at Entergy Louisiana and $34 million at System Energy and long-term DOE obligations of $181$182 million at Entergy Arkansas, and includes debt due within one year. Fair values are classified as Level 2 in the fair value hierarchy discussed in Note 1615 to the financial statements and are based on prices derived from inputs such as benchmark yields and reported trades. |
| |
| (d) | The bonds are secured by a series of collateral first mortgage bonds. |
| |
| (e) | The interest rate as of December 31, 2016 was 8.09%. The interest rate as of December 31, 2015 was an overall implicit rate of 7.45% which included the equity portion of the lease obligation. See Note 10 to the financial statements for further discussion of Entergy Louisiana’s acquisition of the equity participant’s beneficial interest in the Waterford 3 leased assets in March 2016. |
| |
| (f) | This note does not have a stated interest rate, but has an implicit interest rate of 7.458%. |
The annual long-term debt maturities (excluding lease obligations and long-term DOE obligations) for debt outstanding as of December 31, 2015,2016, for the next five years are as follows:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2016 |
| $55,000 |
| |
| $20,600 |
| |
| $125,000 |
| |
| $4,973 |
| |
| $— |
| |
| $— |
| |
| 2017 |
| $114,700 |
| |
| $100,000 |
| |
| $— |
| |
| $2,104 |
| |
| $— |
| |
| $50,000 |
|
| $114,700 |
| |
| $142,703 |
| |
| $— |
| |
| $2,104 |
| |
| $— |
| |
| $50,000 |
|
| 2018 |
| $— |
| |
| $675,000 |
| |
| $— |
| |
| $2,077 |
| |
| $49,614 |
| |
| $85,000 |
|
| $— |
| |
| $675,000 |
| |
| $— |
| |
| $2,077 |
| |
| $23,584 |
| |
| $85,000 |
|
| 2019 |
| $— |
| |
| $— |
| |
| $150,000 |
| |
| $1,979 |
| |
| $617,462 |
| |
| $— |
|
| $— |
| |
| $— |
| |
| $150,000 |
| |
| $1,979 |
| |
| $574,899 |
| |
| $— |
|
| 2020 |
| $— |
| |
| $320,000 |
| |
| $— |
| |
| $26,838 |
| |
| $— |
| |
| $— |
|
| $— |
| |
| $320,000 |
| |
| $— |
| |
| $26,838 |
| |
| $— |
| |
| $— |
|
| 2021 | |
| $534,548 |
| |
| $240,000 |
| |
| $— |
| |
| $1,618 |
| |
| $200,000 |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas Debt Issuances
In January 2016, Entergy Arkansas issued $325 million of 3.5% Series first mortgage bonds due April 2026. Entergy Arkansas used the proceeds to pay, prior to maturity, its $175 million of 5.66% Series first mortgage bonds due February 2025, and expects to use the remainder of the proceeds, together with other funds, towards the purchase of a power block at the Union Power Station and for general corporate purposes.
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 in the tables above, Entergy Arkansas Restoration Funding expects to make principal payments on the bonds over the next fivefour years in the amount of $13.4 million for 2016, $13.8 million for 2017, $14.1 million for 2018, $14.4 million for 2019, and $7.3 million for 2020. 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 canceled 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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
rate of 2.04% and an expected maturity date of June 2021.. Although the principal amount is not due until the date given in the tables above, Entergy Louisiana Investment Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $21.6 million for 2016, $21.7 million for 2017, $22.3 million for 2018, $22.7 million for 2019, and $23.2 million for 2020.2020, and $11 million for 2021. 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. 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 New Orleans Securitization Bonds - Hurricane Isaac
In May 2015 the City Council issued a financing order authorizing the issuance of securitization bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associated with the securitization. In July 2015, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated by Entergy New Orleans, issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67% and an expected maturity date of June 2024.. Although
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the principal amount is not due until the date given in the tables above, Entergy New Orleans Storm Recovery Funding expects to make principal payments on the bonds over the next five years in the amounts of $11.4 million for 2016, $10.6 million for 2017, $11 million for 2018, $11.2 million for 2019, and $11.6 million for 2020.2020, and $11.9 million for 2021.
With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans 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 New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm 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’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 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 $26 million for 2016, $27.6 million for 2017, $29.2 million for 2018, $30.9 million for 2019, and $32.8 million for 2020. All of the scheduled principal payments2020, and $17.5 million for 2016 are for Tranche A-2, $23.6 million of2021. Of the scheduled principal payments for 2017, $23.6 million are for Tranche A-2, and $4 million of the scheduled principal payments for 2017 are for Tranche A-3. All of the scheduled principal payments for 2018-20202018-2021 are for Tranche A-3. Tranche A-1 has been paid.
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 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’s Hurricane Ike and Hurricane Gustav restoration costs, plus carrying costs and transaction 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 $42.6 million for 2016, $44.1 million for 2017, $45.8 million for 2018, $47.6 million for 2019, and $49.8 million for 2020.2020, and $52 million for 2021. All of the scheduled principal payments for 2016-20172017 are for Tranche A-2, $30.8 million of the scheduled principal payments for 2018 are for Tranche A-2 and $15 million are for Tranche A-3. All of the scheduled principle payments for 2019-20202019-2021 are for Tranche A-3. Tranche A-1 has been paid.
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 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 Corporation and Subsidiaries
Notes to Financial Statements
NOTE 6. PREFERRED EQUITY (Entergy Corporation, Entergy Arkansas, 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 non-controlling interest for Entergy Corporation subsidiaries as of December 31, 20152016 and 20142015 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 | | | | |
| | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 | | 2014 | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 | | 2015 |
| 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 |
| | 313,500 |
| | 3,413,500 |
| | 313,500 |
| | 3,413,500 |
| |
| $31,350 |
| |
| $116,350 |
|
| Entergy Louisiana, Series A 8.25% | | — |
| | 100,000 |
| | — |
| | 100,000 |
| | — |
| | 10,000 |
| |
| Entergy Louisiana, 6.95% Series (a) | | — |
| | 1,000,000 |
| | — |
| | 840,000 |
| | — |
| | 84,000 |
| |
| Entergy Utility Holding Company, LLC, 7.5% Series (b) | | 110,000 |
| | — |
| | 110,000 |
| | — |
| | 107,425 |
| | — |
| |
| Entergy Utility Holding Company, LLC, 7.5% Series (a) | | | 110,000 |
| | 110,000 |
| | 110,000 |
| | 110,000 |
| | 107,425 |
| | 107,425 |
|
| Entergy Mississippi, 4.36%-6.25% Series | | 1,403,807 |
| | 1,403,807 |
| | 1,403,807 |
| | 1,403,807 |
| | 50,381 |
| | 50,381 |
| | 203,807 |
| | 1,403,807 |
| | 203,807 |
| | 1,403,807 |
| | 20,381 |
| | 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 | | 5,125,105 |
| | 6,115,105 |
| | 5,125,105 |
| | 5,955,105 |
| | 293,936 |
| | 280,511 |
| | 825,105 |
| | 5,125,105 |
| | 825,105 |
| | 5,125,105 |
| | 178,936 |
| | 293,936 |
|
| Entergy Wholesale Commodities: | | | | | | | | | | | | | | | | | | | | | | | | |
| Preferred Stock without sinking fund: | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Finance Holding, Inc. 8.75% (c) | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 24,249 |
| | 24,249 |
| |
| Entergy Finance Holding, Inc. 8.75% (b) | | | 250,000 |
| | 250,000 |
| | 250,000 |
| | 250,000 |
| | 24,249 |
| | 24,249 |
|
| Total Subsidiaries’ Preferred Stock without sinking fund | | 5,375,105 |
| | 6,365,105 |
| | 5,375,105 |
| | 6,205,105 |
| |
| $318,185 |
| |
| $304,760 |
| | 1,075,105 |
| | 5,375,105 |
| | 1,075,105 |
| | 5,375,105 |
| |
| $203,185 |
| |
| $318,185 |
|
| |
(a) | In 2007, Entergy Louisiana Holdings, an Entergy subsidiary, purchased 160,000 of these shares from the holders. |
| |
(b) | Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs. |
| |
(c) | Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs. |
(a) Dollar amount outstanding is net of $2,575 thousand of preferred stock issuance costs.
(b) Dollar amount outstanding is net of $751 thousand of preferred stock issuance costs.
In October 2015, Entergy Utility Holding Company, LLC issued 110,000 shares of $1,000 par value 7.5% Series Preferred Stock,Membership Interests, all of which are outstanding as of December 31, 2015.2016. The dividends are cumulative and payable quarterly. The preferred stock isThese units are redeemable on or after January 1, 2036, at Entergy Utility Holding Company, LLC’s option, at the fixed redemption price of $1,000 per share.
In December 2013, Entergy Finance Holding, Inc. issued 250,000 shares of $100 par value 8.75% Series Preferred Stock, all of which are outstanding as of December 31, 2015.2016. The dividends are cumulative and payable quarterly. The preferred stock is redeemable on or after December 16, 2023, at Entergy Finance Holding, Inc.’s option, at the fixed redemption price of $100 per share.
The number of shares and units authorized and outstanding and dollar value of preferred stock and membership interests for Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans as of December 31,
Entergy Corporation 2016 and Subsidiaries
Notes to Financial Statements
2015 and 2014 are presented below. All series of the Utility operating companies’ preferred stock and membership interests are redeemable at the respective company’s option at the call prices presented. Dividends and distributions paid on all of Entergy’s preferred stock and membership interests series are eligible for the dividends received deduction.
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 |
| Entergy Arkansas Preferred Stock | | | | | | (Dollars in Thousands) | | |
| 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 | | 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 | | | | Call Price per Unit as of December 31, |
| | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 |
| Entergy Louisiana Preferred Membership Interests | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 liquidation value: | | | | | | | | | | |
| 8.25% Series (a) | | — |
| | 100,000 |
| |
| $— |
| |
| $10,000 |
| |
| $— |
|
| 6.95% Series (a) | | — |
| | 1,000,000 |
| | — |
| | 100,000 |
| |
| $— |
|
| Total without sinking fund | | — |
| | 1,100,000 |
| |
| $— |
| |
| $110,000 |
| | |
| |
(a) | In September 2015, Entergy Louisiana redeemed its $100 million of 6.95% Series preferred membership interests and Entergy Gulf States Louisiana redeemed its $10 million of 8.25% Series preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana Business Combination. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 |
| Entergy Mississippi Preferred Stock | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | |
| 4.36% Series | | 59,920 |
| | 59,920 |
| |
| $5,992 |
| |
| $5,992 |
| |
| $103.86 |
|
| 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 | | 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 | | | | Call Price per Share as of December 31, |
| | | 2015 | | 2014 | | 2015 | | 2014 | | 2015 |
| Entergy New Orleans Preferred Stock | | | | | | (Dollars in Thousands) | | |
| 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 |
| | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 |
| Entergy Arkansas Preferred Stock | | | | | | (Dollars in Thousands) | | |
| 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 |
| | — |
| | 10,000 |
| |
| $— |
|
| Cumulative, $25 par value: | | | | | | | | | | |
| 6.45% Series | | — |
| | 3,000,000 |
| | — |
| | 75,000 |
| |
| $— |
|
| Total without sinking fund | | 313,500 |
| | 3,413,500 |
| |
| $31,350 |
| |
| $116,350 |
| | |
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 |
| Entergy Mississippi Preferred Stock | | | | | | (Dollars in Thousands) | | |
| Without sinking fund: | | | | | | | | | | |
| Cumulative, $100 par value: | | | | | | | | | | |
| 4.36% Series | | 59,920 |
| | 59,920 |
| |
| $5,992 |
| |
| $5,992 |
| |
| $103.86 |
|
| 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 | | — |
| | 1,200,000 |
| | — |
| | 30,000 |
| |
| $— |
|
| Total without sinking fund | | 203,807 |
| | 1,403,807 |
| |
| $20,381 |
| |
| $50,381 |
| | |
|
| | | | | | | | | | | | | | | | | | |
| | | Shares Authorized and Outstanding | | | | Call Price per Share as of December 31, |
| | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 |
| Entergy New Orleans Preferred Stock | | | | | | (Dollars in Thousands) | | |
| 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 |
| | |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 7. COMMON EQUITY (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Common Stock
Common stock and treasury stock shares activity for Entergy for 2016, 2015, 2014, and 20132014 is as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | Common Shares Issued | |
Treasury Shares | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares | Common Shares Issued | |
Treasury Shares | | Common Shares Issued | | Treasury Shares | | Common Shares Issued | | Treasury Shares |
| Beginning Balance, January 1 | 254,752,788 |
| | 75,512,079 |
| | 254,752,788 |
| | 76,381,936 |
| | 254,752,788 |
| | 76,945,239 |
| 254,752,788 |
| | 76,363,763 |
| | 254,752,788 |
| | 75,512,079 |
| | 254,752,788 |
| | 76,381,936 |
|
| Repurchases | — |
| | 1,468,984 |
| | — |
| | 2,154,490 |
| | — |
| | — |
| — |
| | — |
| | — |
| | 1,468,984 |
| | — |
| | 2,154,490 |
|
| Issuances: | |
| | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
| | |
|
| Employee Stock-Based Compensation Plans | — |
| | (610,409 | ) | | — |
| | (3,019,475 | ) | | — |
| | (557,734 | ) | — |
| | (729,073 | ) | | — |
| | (610,409 | ) | | — |
| | (3,019,475 | ) |
| Directors’ Plan | — |
| | (6,891 | ) | | — |
| | (4,872 | ) | | — |
| | (5,569 | ) | — |
| | (11,327 | ) | | — |
| | (6,891 | ) | | — |
| | (4,872 | ) |
| Ending Balance, December 31 | 254,752,788 |
| | 76,363,763 |
| | 254,752,788 |
| | 75,512,079 |
| | 254,752,788 |
| | 76,381,936 |
| 254,752,788 |
| | 75,623,363 |
| | 254,752,788 |
| | 76,363,763 |
| | 254,752,788 |
| | 75,512,079 |
|
Entergy Corporation reissues treasury shares to meet the requirements of the Stock Plan for Outside Directors (Directors’ Plan), twothree 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’ Plan awards to non-employee directors a portion of their compensation in the form of a fixed dollar value of shares of Entergy Corporation common stock.
In October 2010 the Board granted authority for a $500 million share repurchase program. As of December 31, 2015,2016, $350 million of authority remains under the $500 million share repurchase program.
Dividends declared per common share were $3.42 in 2016, $3.34 in 2015, and $3.32 in 2014 and 2013.2014.
In 2015, System Energy paid its parent, Entergy Corporation, a $70 million distributiondistributions out of its common stock.stock of $40 million in 2016 and $70 million in 2015.
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 certaineach of Entergy Corporation’s subsidiariesArkansas, Entergy Mississippi and Entergy New Orleans could restrict the payment of cash dividends or other distributions on their common and preferred equity. Asequity if such payment were to occur when, or result in, a ratio of December 31, 2015, under provisions in their mortgage indentures, Entergy Arkansas and Entergy Mississippi had retained earnings unavailable for distributioncommon stock equity to Entergy Corporationtotal capitalization of $394.9 million and $68.5 million, respectively.25% or less. Entergy Corporation received dividend payments and distributions from subsidiaries totaling $165 million in 2016, $615 million in 2015, and $893 million in 2014, and $702 million in 2013.2014.
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 and Entergy Louisiana. The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 20152016 by component:
| | | | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gains (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gain (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Beginning balance, January 1, 2015 |
| $98,118 |
| |
| ($569,789 | ) | |
| $426,695 |
| |
| $2,669 |
| |
| ($42,307 | ) | |
| Beginning balance, January 1, 2016 | |
| $105,970 |
| |
| ($466,604 | ) | |
| $367,557 |
| |
| $2,028 |
| |
| $8,951 |
|
| Other comprehensive income (loss) before reclassifications | (151,740 | ) | | 71,054 |
| | (34,186 | ) | | (641 | ) | | (115,513 | ) | 87,740 |
| | (26,997 | ) | | 68,465 |
| | (1,280 | ) | | 127,928 |
|
| Amounts reclassified from accumulated other comprehensive income (loss) | 159,592 |
| | 32,131 |
| | (24,952 | ) | | — |
| | 166,771 |
| (189,717 | ) | | 24,155 |
| | (6,288 | ) | | — |
| | (171,850 | ) |
| Net other comprehensive income (loss) for the period | 7,852 |
| | 103,185 |
| | (59,138 | ) | | (641 | ) | | 51,258 |
| (101,977 | ) | | (2,842 | ) | | 62,177 |
| | (1,280 | ) | | (43,922 | ) |
| Ending balance, December 31, 2015 |
| $105,970 |
| |
| ($466,604 | ) | |
| $367,557 |
| |
| $2,028 |
| |
| $8,951 |
| |
| Ending balance, December 31, 2016 | |
| $3,993 |
| |
| ($469,446 | ) | |
| $429,734 |
| |
| $748 |
| |
| ($34,971 | ) |
The following table presents changes in accumulated other comprehensive income (loss) for Entergy for the year ended December 31, 20142015 by component:
|
| | | | | | | | | | | | | | | | | | | |
| | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gains (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) |
| | | | | | | | | | |
| Beginning balance, January 1, 2014 |
| ($81,777 | ) |
|
| ($288,223 | ) |
|
| $337,256 |
|
|
| $3,420 |
| |
| ($29,324 | ) |
| Other comprehensive income (loss) before reclassifications | 52,433 |
| | (278,361 | ) | | 99,900 |
| | (751 | ) | | (126,779 | ) |
Amounts reclassified from
accumulated other comprehensive
income (loss) | 127,462 |
| | (3,205 | ) | | (10,461 | ) | | — |
| | 113,796 |
|
| Net other comprehensive income (loss) for the period | 179,895 |
| | (281,566 | ) | | 89,439 |
| | (751 | ) | | (12,983 | ) |
| Ending balance, December 31, 2014 |
| $98,118 |
| |
| ($569,789 | ) | |
| $426,695 |
| |
| $2,669 |
| |
| ($42,307 | ) |
|
| | | | | | | | | | | | | | | | | | | |
| | Cash flow
hedges
net
unrealized
gain (loss) | | Pension
and
other
postretirement
liabilities | |
Net
unrealized
investment
gain (loss) | | Foreign
currency
translation | | Total
Accumulated
Other
Comprehensive
Income (Loss) |
| | (In Thousands) |
| | | | | | | | | | |
| Beginning balance, January 1, 2015 |
| $98,118 |
|
|
| ($569,789 | ) |
|
| $426,695 |
|
|
| $2,669 |
| |
| ($42,307 | ) |
| Other comprehensive income (loss) before reclassifications | (151,740 | ) | | 71,054 |
| | (34,186 | ) | | (641 | ) | | (115,513 | ) |
Amounts reclassified from
accumulated other comprehensive income (loss) | 159,592 |
| | 32,131 |
| | (24,952 | ) | | — |
| | 166,771 |
|
| Net other comprehensive income (loss) for the period | 7,852 |
| | 103,185 |
| | (59,138 | ) | | (641 | ) | | 51,258 |
|
| Ending balance, December 31, 2015 |
| $105,970 |
| |
| ($466,604 | ) | |
| $367,557 |
| |
| $2,028 |
| |
| $8,951 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2015:2016:
|
| | | | |
| | | Pension and Other Postretirement Liabilities |
| | | (In Thousands) |
| | | |
Beginning balance, January 1, 20152016 | |
| ($79,22356,412 | ) |
| Other comprehensive income (loss) before reclassifications | | 21,1808,926 |
|
Amounts reclassified from accumulated other comprehensive income (loss) | | 1,631(956 |
) |
| Net other comprehensive income (loss) for the period | | 22,8117,970 |
|
Ending balance, December 31, 20152016 | |
| ($56,41248,442 | ) |
The following table presents changes in accumulated other comprehensive income (loss) for Entergy Louisiana for the year ended December 31, 2014:2015:
|
| | | | |
| | Pension and Other
Postretirement Liabilities |
| | (In Thousands) |
| | | |
Beginning balance, January 1, 20142015 | |
| ($37,83779,223 | ) |
| Other comprehensive income (loss) before reclassifications | | (40,75521,180 | )
|
Amounts reclassified from accumulated other
comprehensive income (loss) | | (6311,631 | )
|
| Net other comprehensive income (loss) for the period | | (41,38622,811 | )
|
Ending balance, December 31, 20142015 | |
| ($79,22356,412 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the yearyears ended December 31, 2016 and 2015 are as follows:
|
| | | | | | |
| | Amounts
reclassified
from
AOCI
| | Income Statement Location |
| | (In Thousands) | | |
| | | | |
Cash flow hedges net unrealized gain (loss) | | | | |
Power contracts | |
| ($243,555 | ) | | Competitive business operating revenues |
Interest rate swaps | | (1,971 | ) | | Miscellaneous - net |
Total realized gain (loss) on cash flow hedges | | (245,526 | ) | | |
| | 85,934 |
| | Income taxes |
Total realized gain (loss) on cash flow hedges (net of tax) | |
| ($159,592 | ) | | |
| | | | |
Pension and other postretirement liabilities | | |
| | |
Amortization of prior-service costs | |
| $23,920 |
| | (a) |
Acceleration of prior-service cost due to curtailment | | (374 | ) | | (a) |
Amortization of loss | | (70,296 | ) | | (a) |
Settlement loss | | (1,401 | ) | | (a) |
Total amortization | | (48,151 | ) | | |
| | 16,020 |
| | Income taxes |
Total amortization (net of tax) | |
| ($32,131 | ) | | |
| | | | |
Net unrealized investment gain (loss) | | | | |
Realized gain (loss) | |
| $48,926 |
| | Interest and investment income |
| | (23,974 | ) | | Income taxes |
Total realized investment gain (loss) (net of tax) | |
| $24,952 |
| | |
| | | | |
Total reclassifications for the period (net of tax) | |
| ($166,771 | ) | | |
|
| | | | | | | | | | |
| | | Amounts reclassified from AOCI | | Income Statement Location |
| | | 2016 | | 2015 | | |
| | | (In Thousands) | | |
| Cash flow hedges net unrealized gain (loss) | | | | | | |
| Power contracts | |
| $293,268 |
| |
| ($243,555 | ) | | Competitive business operating revenues |
| Interest rate swaps | | (1,395 | ) | | (1,971 | ) | | Miscellaneous - net |
| Total realized gain (loss) on cash flow hedges | | 291,873 |
| | (245,526 | ) | | |
| | | (102,156 | ) | | 85,934 |
| | Income taxes |
| Total realized gain (loss) on cash flow hedges (net of tax) | |
| $189,717 |
| |
| ($159,592 | ) | | |
| | | | |
| | |
| Pension and other postretirement liabilities | | |
| | |
| | |
| Amortization of prior-service costs | |
| $29,414 |
| |
| $23,920 |
| | (a) |
| Acceleration of prior-service cost due to curtailment | | (1,045 | ) | | (374 | ) | | (a) |
| Amortization of loss | | (60,693 | ) | | (70,296 | ) | | (a) |
| Settlement loss | | (2,007 | ) | | (1,401 | ) | | (a) |
| Total amortization | | (34,331 | ) | | (48,151 | ) | | |
| | | 10,176 |
| | 16,020 |
| | Income taxes |
| Total amortization (net of tax) | |
| ($24,155 | ) | |
| ($32,131 | ) | | |
| | | | |
| | |
| Net unrealized investment gain (loss) | | | |
| | |
| Realized gain (loss) | |
| $12,329 |
| |
| $48,926 |
| | Interest and investment income |
| | | (6,041 | ) | | (23,974 | ) | | Income taxes |
| Total realized investment gain (loss) (net of tax) | |
| $6,288 |
| |
| $24,952 |
| | |
| | | | |
| | |
| Total reclassifications for the period (net of tax) | |
| $171,850 |
| |
| ($166,771 | ) | | |
|
| |
| (a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy for the year ended December 31, 2014 are as follows:
|
| | | | | | |
| | Amounts
reclassified
from
AOCI | | Income Statement Location |
| | (In Thousands) | | |
|
|
|
|
|
Cash flow hedges net unrealized gain (loss) | |
| |
|
Power contracts |
|
| ($193,297 | ) |
| Competitive business operating revenues |
Interest rate swaps |
| (2,799 | ) |
| Miscellaneous - net |
Total realized gain (loss) on cash flow hedges |
| (196,096 | ) |
|
|
|
| 68,634 |
|
| Income taxes |
Total realized gain (loss) on cash flow hedges (net of tax) |
|
| ($127,462 | ) |
|
|
|
|
|
|
|
Pension and other postretirement liabilities | | |
| |
|
Amortization of prior-service costs | |
| $20,294 |
| | (a) |
Amortization of loss |
| (35,836 | ) |
| (a) |
Settlement loss |
| (3,643 | ) |
| (a) |
Total amortization |
| (19,185 | ) |
|
|
|
| 22,390 |
|
| Income taxes |
Total amortization (net of tax) |
|
| $3,205 |
|
|
|
|
|
|
|
|
Net unrealized investment gain (loss) |
|
|
|
|
Realized gain (loss) |
|
| $20,511 |
|
| Interest and investment income |
|
| (10,050 | ) |
| Income taxes |
Total realized investment gain (loss) (net of tax) |
|
| $10,461 |
|
|
|
|
|
|
|
|
Total reclassifications for the period (net of tax) | |
| ($113,796 | ) | |
|
|
| |
(a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the yearyears ended December 31, 2016 and 2015 are as follows:
|
| | | | | | |
| | Amounts reclassified | | | | | | | | | | | | | | | Amounts reclassified from AOCI | | Income Statement Location | | | | 2016 | | 2015 | | | | | | (In Thousands) | | | | | | | | | | | | Pension and other postretirement liabilities | | | | | | | | Amortization of prior-service costs | |
| $7,786 |
| |
| $7,464 |
| | (a) | | Amortization of loss | | (6,281 | ) | | (10,140 | ) | | (a) | | Settlement loss | | — |
| | (14 | ) | | (a) | | Total amortization | | 1,505 |
| | (2,690 | ) | | | | | | (549 | ) | | 1,059 |
| | Income taxes | | Total amortization (net of tax) | | 956 |
| | (1,631 | ) | | | | | | | |
| | | | Total reclassifications for the period (net of tax) | |
| $956 |
| |
| ($1,631 | ) | | |
from AOCI
| | Income Statement Location |
| | (In Thousands) | | |
| | | | |
Pension and other postretirement liabilities | | | | |
Amortization of prior-service costs | |
| $7,464 |
| | (a) |
Amortization of loss | | (10,140 | ) | | (a) |
Settlement loss | | (14 | ) | | (a) |
Total amortization | | (2,690 | ) | | |
| | 1,059 |
| | Income taxes |
Total amortization (net of tax) | | (1,631 | ) | | |
| | | | |
Total reclassifications for the period (net of tax) | |
| ($1,631 | ) | | |
|
| |
| (a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details. |
Total reclassifications out of accumulated other comprehensive income (loss) (AOCI) for Entergy Louisiana for the year ended December 31, 2014 are as follows:
|
| | | | | | |
| | Amounts reclassified
from AOCI |
| Income Statement Location |
| | (In Thousands) | | |
|
|
|
|
|
Pension and other postretirement liabilities |
|
| |
|
Amortization of prior-service costs | |
| $5,614 |
| | (a) |
Amortization of loss | | (4,637 | ) | | (a) |
Total amortization |
| 977 |
|
|
|
| | (346 | ) |
| Income taxes |
Total amortization (net of tax) |
| 631 |
|
|
|
|
|
|
|
|
Total reclassifications for the period (net of tax) | |
| $631 |
| |
|
|
| |
(a) | These accumulated other comprehensive income (loss) components are included in the computation of net periodic pension and other postretirement cost. See Note 11 to the financial statements for additional details.
|
NOTE 8. COMMITMENTS AND CONTINGENCIES (Entergy Corporation, Entergy Arkansas, 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 effect on Entergy’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 $158.7 million in 2016, $146 million in 2015, and $152.8 million in 2014, and $181.1 million in 2013.2014. If the maximum percentage (94%) of the energy is made available to Entergy Louisiana, current production projections would require estimated payments of approximately $150.5$129 million in 2016,2017, and a total of $1.93$1.81 billion for the years 20172018 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 10 years, beginning in October 2002. In October 2011 the LPSC approved a settlement under which Entergy Louisiana agreed to provide credits to customers by crediting billings an additional $20.235 million per year for 15 years beginning January 2012. Entergy Louisiana recorded a regulatory charge and a corresponding regulatory liability to reflect this obligation.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
ANO Damage, Outage, and NRC Reviews
OnIn March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Arkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Litigation remains pending.
In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.
Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL. In July 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.
Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In May 2014 the NRC met with Entergy during a regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO.
In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held in October 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
In March 2015, after several NRC inspections and regulatory conferences, the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4)column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also expects to incurincurred approximately $50$44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A much lesser amount of incremental expensesexpense is expected to be ongoing annually after 2016.2016, until ANO transitions out of Column 4.
Baxter Wilson Plant EventThe NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the completion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4.
On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event. Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy and has received all of its previously-accrued insurance proceeds, with $12.9 million allocated to capital spending and $15.3 million allocated to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Pilgrim NRC Oversight and Planned Shutdown
In September 2015 the NRC placed Pilgrim in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix due to its finding of continuing weaknesses in Pilgrim’s corrective action program that contributed to repeated unscheduled shutdowns and equipment failures. The preliminary estimate of direct costs of Pilgrim’s response to a planned NRC enhanced inspection ranges from $45 million to $60 million, including approximately $30of which $28.6 million was incurred in 2016 in operation and maintenance expense,expense. The estimate does not including anyinclude potential capital investmentexpenditures, which will be charged directly to expense when incurred, or other costs to address issues that may arise in the inspection.
Entergy determined in October 2015 that it willwould close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision to place the plant in Column 4. Entergy determined in April 2016 that it intends to refuel Pilgrim in 2017 and then cease operations May 31, 2019. Pilgrim currently has approximately 677 MW of Capacity Supply Obligations in ISO New England through May 2019. If Pilgrim shuts down earlier than June 2019 it could have to buy back its Capacity Supply Obligations at prices higher than the capacity rates Pilgrim is currently scheduled to receive. The precise timing of the shutdown depends on several factors, including further discussion with ISO New England. Management expects the timing of the shutdown will be decided in the first half of 2016.
See Note 114 to the financial statements for discussion of the impairment of the Pilgrim plant and related long-lived assets.
Spent Nuclear Fuel Enrichment ContractsLitigation
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’s nuclear owner/licensee subsidiaries have been charged fees 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 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. Following the defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
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. 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. Beginning in November 2003 these subsidiaries have pursued litigation to recover the damages caused by the DOE’s delay in performance. Following are details of final judgments recorded by Entergy in 2016 related to Entergy’s nuclear owner licensee subsidiaries’ litigation with the DOE.
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016. The effect of recording the Indian Point 3 proceeds was a reduction to plant, other operation and maintenance expense, and depreciation expense. The Indian
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Point 3 damages awarded included $45 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $45 million, Entergy recorded $8 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 3 plant asset balance by the remaining $37 million. The effect of recording the FitzPatrick proceeds was a reduction to plant and other operation and maintenance expense. The FitzPatrick damages awarded included $32 million related to costs previously capitalized and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $32 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense, a $10 million reduction to bring its remaining FitzPatrick plant asset balance to zero, and the excess was recorded as a reduction to other operations and maintenance expense. See Note 14 for further discussion on the fair value analysis performed for FitzPatrick and the related impairment charge.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case. Entergy Louisiana received payment from the U.S. Treasury in August 2016. The effects of recording the final judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The River Bend damages awarded included $17 million related to costs previously capitalized, $23 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $17 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy Louisiana reduced its River Bend plant asset balance by the remaining $14 million. In September 2016 the U.S. Court of Federal Claims issued a further judgment in the River Bend case in the amount of $5 million. Entergy Louisiana recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The River Bend damages awarded included $2 million related to costs previously recorded as nuclear fuel expense and $3 million related to costs previously recorded as other operation and maintenance expense.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulation agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of Entergy Nuclear Vermont Yankee and against the DOE in the second round Vermont Yankee damages case. Entergy received payment from the U.S. Treasury in June 2016. The effect of recording the proceeds was a reduction to other operation and maintenance expense and depreciation expense. The damages awarded included $15 million related to costs previously capitalized and $4 million related to costs previously recorded as other operation and maintenance expense. Of the $15 million, Entergy recorded $2 million as a reduction to previously-recorded depreciation expense. The remaining $13 million would have been recorded as a reduction to Vermont Yankee’s plant asset balance, but was recorded as a reduction to other operation and maintenance expense because Vermont Yankee’s plant asset balance is fully impaired.
In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. System Energy received payment from the U.S. Treasury in August 2016. The effects of recording the judgment in the third quarter 2016 were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The amounts of Grand Gulf damages awarded related to System Energy’s 90% ownership of Grand Gulf included $16 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, and $9 million related to costs previously recorded as other operation and maintenance expense. Of the $16 million, System Energy recorded $5 million as a reduction to previously-recorded depreciation expense. System Energy reduced its Grand Gulf plant asset balance by the remaining $11 million.
In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Entergy Arkansas received payment from the U.S. Treasury in October 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, and other operation and maintenance expense. The ANO damages awarded included $6 million related to costs previously capitalized, $19 million related to costs previously recorded as nuclear fuel expense, $5 million related to costs previously recorded as other operation and maintenance expense, and $1 million related to costs previously recorded as taxes other than income taxes.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In August 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $53 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. Entergy Louisiana received payment from the U.S. Treasury in November 2016. The effects of recording the judgment were reductions to plant, nuclear fuel expense, other operation and maintenance expense, and depreciation expense. The Waterford 3 damages awarded included $41 million related to costs previously capitalized, $10 million related to costs previously recorded as nuclear fuel expense, and $2 million related to costs previously recorded as other operation and maintenance expense. Of the $41 million, Entergy Louisiana recorded $3 million as a reduction to previously-recorded depreciation expense.
In September 2016 the U.S. Court of Federal Claims issued a judgment in the Entergy Nuclear Palisades case in the amount of $14 million. Entergy Nuclear Palisades recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Palisades damages awarded included $11 million related to costs previously capitalized and $3 million related to costs previously recorded as other operation and maintenance expense. Of the $11 million, Entergy recorded $1 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Palisades plant asset balance by the remaining $10 million. The Court previously issued a partial judgment in the case in the amount of $21 million, which was paid by the U.S. Treasury in October 2015.
In October 2016 the U.S. Court of Federal Claims issued a judgment in the second round Entergy Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 recorded a receivable for that amount, and subsequently received payment from the U.S. Treasury in January 2017. The effects of recording the judgment were reductions to plant and other operation and maintenance expenses. The Indian Point 2 damages awarded included $14 million related to costs previously capitalized, $15 million related to costs previously recorded as other operation and maintenance expense, $3 million related to previously recorded decommissioning expense, and $2 million related to costs previously recorded as taxes other than income taxes. Of the $14 million, Entergy recorded $3 million as a reduction to previously-recorded depreciation expense. Entergy reduced its Indian Point 2 plant asset balance by the remaining $11 million.
Management cannot predict the timing or amount of any potential recoveries on other claims filed by Entergy subsidiaries, are parties to two contracts with American Centrifuge Enrichment, LLC (ACE) under which these subsidiaries purchase nuclear fuel enrichment services. The termand cannot predict the timing of each contract isany eventual receipt from 2011 to 2022; however, each contract provided for cancellationthe DOE of the parties’ purchase and sale obligations for 2016-2022 if, by August 1, 2014, ACE’s planned Advanced Centrifuge Plant was not in commercial operation and ACE did not identify to Entergy’s reasonable satisfaction how it would meet its contractual delivery obligations through output from ACE. In August 2014, Entergy sent notice to ACE that the 2016-2022 obligations were canceled by the operationU.S. Court of this contractual provision. United States Enrichment Corporation (USEC), ACE’s affiliate to which ACE assigned the contracts, filed a demand for arbitration with the American Arbitration Association, claiming damages of approximately $165 million. In July 2015 the parties reached an agreement resolving the dispute that resulted in the dismissal of USEC’s claims. The resolution of the dispute does not have a material effect on Entergy’s results of operations, financial position, or cash flows.Federal Claims damage awards.
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:
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| 1. | The primary level is private insurance underwritten by American Nuclear Insurers (ANI) and provides public liability insurance coverage of $450 million for each operating reactor (prior to January 1, 2017, the primary level of insurance was $375 million.million). If this amount is not sufficient to cover claims arising from an accident, the second level, Secondary Financial Protection, applies. In 2016 the NRC approved Vermont Yankee’s exemption request to lower their limits from $375 million to $100 million effective April 15, 2016. |
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| 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 approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4$1.273 billion). This consists of a $121.3 million maximum retrospective premium plus a five percent surcharge, which equates to $127.3 million, that may beis payable if needed, at a rate that is currently set at approximately $19 million per year per incident per nuclear power reactor. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| 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 $13.5approximately $13 billion in coverage. 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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed intoUnder current law, by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31,extends through 2020. |
Currently, 103102 nuclear reactors are participating in the Secondary Financial Protection program. Effective April 15, 2016 the NRC granted Vermont Yankee’s exemption request and it was allowed to withdraw from participation in this layer of financial protection. The product of the maximum retrospective premium assessment to the nuclear power industry and the number of nuclear power reactorsSecondary Financial Protection program provides over $13.1approximately $13 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 and Entergy Louisiana each have two licensed reactors. System Energy has one licensed reactor (10% of Grand Gulf is owned by a non-affiliated company (SMEPA)(Cooperative Energy) that would share on a pro-rata basis in any retrospective premium assessment to System Energy under the Price-Anderson Act). The Entergy Wholesale Commodities segment includes the ownership, operation, and decommissioning of nuclear power reactors and the ownership of the shutdown Indian Point 1 reactor and Big Rock Point facility.
Property Insurance
Entergy’s nuclear owner/licensee subsidiaries are members of NEIL, a mutual insurance company that provides property damage coverage, including decontamination and premature decommissioning expense, to the members’ nuclear generating plants. Effective April 1, 2015,The property damage insurance limits procured by Entergy was insured against such losses perfor its Utility plants and Entergy Wholesale Commodity plants are in compliance with the following structures:financial protection requirements of the NRC.
As of December 31, 2016, the Utility Plantsplants (ANO 1 and 2, Grand Gulf, River Bend, and Waterford 3) had property damage insurance limits as follows: $1.5 billion per occurrence at each plant with an additional $100 million per occurrence that is shared among the plants. Property damage from flood, earthquake, and volcanic eruption is excluded from the first $500 million in coverage for ANO 1 and 2 and Grand Gulf. Property damage from earthquake and volcanic eruption is excluded from the first $500 million in coverage for River Bend and Waterford 3.
Primary Layer (per plant)
As of December 31, 2016, the Entergy Wholesale Commodities’ plants (FitzPatrick, Pilgrim, Palisades, Indian Point, Vermont Yankee, and Big Rock Point) had property damage insurance limits as follows: Vermont Yankee - $50 million per occurrence; Big Rock Point - $500 million per occurrence; FitzPatrick, Pilgrim, and Palisades - $1.115 billion per occurrence (FitzPatrick and Pilgrim’s coverage for non-nuclear, non-radiological property damage is limited to $500 million per occurrence); and Indian Point - $1.5 billion per occurrence
Blanket Excess Layer (shared among the Utility plants) - (Indian Point has additional coverage of $100 million per occurrence,
Total limit - which brings its total insurance to $1.6 billion per occurrence
Deductibles:
$2.5 million per occurrence - Turbine/generatorbillion). Property 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, orand volcanic eruption
Note: ANO 1 and 2 share in the primary and blanket excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are is excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood coverage at Waterford 3for FitzPatrick and River Bend forPilgrim. Property damage from earthquake and volcanic eruption is excluded from the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plants (FitzPatrick, Pilgrim, and Palisades)
Primary Layer (per plant) - $1.115 billion per occurrence
Total limit (per plant) - $1.115 billion per occurrence
Deductibles:
$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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Palisades for the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plant (Indian Point)
Primary Layer (per plant) - $1.5 billion per occurrence
Excess Layer - $100 million per occurrence
Total limit - $1.6 billion per occurrence
Deductibles:
$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 eruptionIndian Point.
Note: The Indian Point Units share in the primary and excess layers with common policies because the policies are issued on a per site basis. Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood coverage at Indian Point for the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plant (Vermont Yankee)
Primary Layer (per plant) - $1.06 billion per occurrence
Total limit - $1.06 billion per occurrence
Deductibles:
$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: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Vermont Yankee for the primary layer’s first $500 million in coverage.
Entergy Wholesale Commodities Plant (Big Rock Point)
Primary Layer (per plant) - $500 million per occurrence
Total limit - $500 million per occurrence
Note: Flood and earthquake coverage are excluded from the primary layer’s first $500 million in coverage. Entergy currently purchases flood and earthquake coverage at Big Rock Point for the primary layer’s first $500 million in coverage.
In addition, Waterford 3, Grand Gulf, and the Entergy Wholesale Commodities plants, with the exception of Vermont Yankee, are also covered under NEIL’s Accidental Outage Coverage program. Due to the shutdown of the Vermont Yankee Nuclear Power Plant in December 2014 accidental outage coverage was removed effective October 1, 2014. Accidental outage coverage provides indemnification for the actual cost incurred in the event of an unplanned outage resulting from property damage covered under the NEIL Primary Property Insurance policy, subject to a deductible period. The indemnification for the actual cost incurred is based on market power prices at the time of the loss. TheFor non-nuclear events, the maximum payout indemnity, under this policy, is limited to a $327.6 million per occurrence. WeeklyAfter the deductible period has passed, weekly indemnities for an unplanned outage, covered under NEIL’s Accidental Outage Coverage program, after the deductible period has passed would be paid according to the maximum amounts listed below:
Entergy Corporation and Subsidiaries
Notes to Financial Statements
100% of the weekly indemnity for each week for the first payment period of 52 weeks:weeks; then
80% of the weekly indemnity for each week for the second payment period of 52 weeks; and thereafter
80% of the weekly indemnity for an additional 58 weeks for the third and final payment period.
The following summarizes this coverage effective April 1, 2015:
Waterford 3
$2.95 million weekly indemnity
$413 million maximum indemnity - nuclear
$277 million maximum indemnity - non-nuclear
Deductible: 26 week deductible period
Grand Gulf
$400,000 weekly indemnity (total for four policies)
$56 million maximum indemnity - nuclear (total for four policies)
$37 million maximum indemnity - non- nuclear (total for four policies)
Deductible: 26 week deductible period
Indian Point 2, Indian Point 3, and Palisades
$4.5 million weekly indemnity
$490 million maximum indemnity - nuclear
$327.6 million maximum indemnity - non-nuclear
Deductible: 12 week deductible period
FitzPatrick and Pilgrim
$4 million weekly indemnity
$490 million maximum indemnity - nuclear
$327.6 million maximum indemnity - non-nuclear
Deductible: 12 week deductible 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, 2015,2016, the maximum amounts of such possible assessments per occurrence were as follows:
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| | Assessments |
| | (In Millions) |
| Utility: | |
| Entergy Arkansas | $44.653.6 |
| Entergy Louisiana | $54.756.1 |
| Entergy Mississippi | $0.10 |
| Entergy New Orleans | $0.10 |
| Entergy Texas | N/A |
| System Energy | $24.525.3 |
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| Entergy Wholesale Commodities | $— |
Potential assessments for the Entergy Wholesale Commodities plants are covered by insurance obtained through NEIL’s reinsurers.
Entergy maintains property insurance for its nuclear units in excess of the NRC’s minimum requirement of $1.06 billion per site for nuclear power plant licensees. NRC regulations provide that the proceeds of this insurance
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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. The Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. The Terrorism Risk Insurance Reauthorization Act of 2015, however, was signed into law by the President of the United States in January 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.
Conventional Property Insurance
Entergy’s conventional property insurance program provides coverage on a system-wide basis for Entergy’s non-nuclear assets. The insurance program provides coverage up to $400 million for all perils on a per occurrence, “each and every loss” basis in excess of a $20 million self-insured retention with the exception of the following perils: earthquake shock, flood, and Named Windstorm (including associated storm surge). For the perils of earthquake shock and flood, the insurance program provides coverage up to $400 million on an Entergy system-wideannual aggregate basis in excess of a $40 million self-insured retention, and for all operational perils (direct physical loss or damage due to machinery breakdown, electrical failure, fire, lightning, hail, or explosion) on an “each and every loss” basis;the peril of a Named Windstorm (including associated storm surge), the insurance program provides coverage up to $400$125 million in coverage for certain natural perils (direct physical loss or damage due to earthquake, tsunami, and flood) on an annual aggregate basis; up to $125basis in excess of a $40 million for certain other natural perils (direct physical loss or damage due to a named windstorm and associated storm surge) on an annual aggregate basis; and up to $400 million inself-insured retention. The 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 propertyprovided by the insurance program provides up to $50 million in coverage for the Entergy New Orleans gas distribution system on an “each and every loss” basis. Thisis limited to $50 million limitper occurrence and is subject to:to the $400 millionsame annual aggregate limitlimits and retentions listed above for the natural perils of earthquake tsunami,shock, flood, and flood; the $125 million annual aggregate limit for the natural perils of named windstorm andNamed Windstorm (including associated storm surge. 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 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.surge).
Covered property generally includes power plants, substations, facilities, inventories, and gas distribution-related properties. Excluded property generally includes above-ground transmission and distribution lines, poles, and towers for substations valued at $5 million or less, coverage for named windstorm and associated storm surge is excluded. This coverage is in place for Entergy Corporation, the Registrant Subsidiaries, and certain other Entergy subsidiaries,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
including the owners of the nuclear power 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. As discussed above, the Terrorism Risk Insurance Reauthorization Act of 2007 expired on December 31, 2014. However, The Terrorism Risk Insurance Reauthorization Act of 2015 was signed into law by the President of the United States on January 12, 2015 thereby extending the Terrorism Risk Insurance Act for six years until December 31, 2020.
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 generally $100,000 to $250,000 except for properties thatthe locations scheduled in the policy, with the following exceptions: 1) locations where damage is caused by a Named Windstorm (including associated storm surge) and locations with values in excess of $20 million are damaged by flooding and properties whose values are greater than $20 million; these properties havesubject to a $500,000 deductible. Due to the removal of the Vermont Yankee assets from this additional coverage, as of June 1, 2015,deductible; and 2) three scheduled locations at two nuclear locations havesites are subject to a $2.5 million deductible, which coincides with the nuclear property insurance deductible at each of the respective nuclear site.
Entergy Corporation and Subsidiaries
Notes to Financial Statementssites.
Gas System Rebuild Insurance Proceeds (Entergy New Orleans)
Entergy New Orleans received insurance proceeds in 2007 for future construction expenditures associated with rebuilding its gas system, and the October 2006 City Council resolution approving the settlement of Entergy New 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 system rebuild insurance proceeds” on Entergy New Orleans’s balance sheet.
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 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 or concerning the National Labor Relations Act; claims of retaliation; claims of harassment and hostile work environment; and claims for or regarding benefits under various Entergy Corporation-sponsored plans. Entergy and the Registrant Subsidiaries are responding to these lawsuits 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.
Asbestos Litigation (Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas)
Numerous lawsuits have been filed in federal and state courts, primarily by contractor employees who worked in the 1940-1980s timeframe, primarily against 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 40080 lawsuits involving approximately 4,000600 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Grand Gulf - Related Agreements
Capital Funds Agreement (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 interest in Grand Gulf, and to make payments that, together with other available funds, are adequate to cover System Energy’s operating expenses. System Energy would have to secure funds from other sources, including Entergy Corporation’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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 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’ respective entitlement to receive capacity and energy and are payable irrespective of the quantity of energy 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’s retirement from service. In December 2016 the NRC granted the extension of Grand Gulf’s operating license to 2044. Monthly obligations are based on actual capacity and energy costs. The average monthly payments for 20152016 under the agreement are approximately $19.2$16.7 million for Entergy Arkansas, $7.7$6.7 million for Entergy Louisiana, $16.5$14.3 million for Entergy Mississippi, and $9.3$8.1 million for Entergy New Orleans. See Note 2 to the financial statements for discussion of the complaint filed with the FERC against System Energy seeking a reduction in the return on equity component of the Unit Power Sales Agreement.
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’s operating expenses as defined, including an amount sufficient to amortize the cost of Grand Gulf 2 over 27 years (See Reallocation Agreement terms 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 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’s
Entergy Corporation and Subsidiaries
Notes to Financial Statements
responsibilities and obligations with respect to Grand Gulf under the Availability Agreement. FERC’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’s obligation to System Energy’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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 9. ASSET RETIREMENT OBLIGATIONS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Accounting standards require companies to record liabilities for all legal obligations associated with the retirement of long-lived assets that result from the normal operation of the 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.
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, |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas | $85.7 | | $59.0 | $128.5 | | $85.7 |
| Entergy Louisiana | ($68.3) | | ($82.6) | ($53.9) | | ($68.3) |
| Entergy Mississippi | $77.5 | | $76.3 | $82.0 | | $77.5 |
| Entergy New Orleans | $29.4 | | $35.2 | $40.1 | | $29.4 |
| Entergy Texas | $25.8 | | $18.9 | $33.5 | | $25.8 |
| System Energy | $54.8 | | $55.7 | $69.7 | | $54.8 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2016 and 2015 by Entergy were as follows:
| | | | Liabilities as of December 31, 2014 | | Liabilities Incurred (a) | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2015 | Liabilities as of December 31, 2015 | | Liabilities Incurred | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2016 (a) |
| | (In Millions) | (In Millions) |
| Utility: | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | $818.4 | |
| $3.5 |
| |
| $50.4 |
| |
| $— |
| |
| $— |
| |
| $872.3 |
|
| $872.3 |
| |
| $— |
| |
| $53.6 |
| |
| $— |
| |
| ($1.5 | ) | |
| $924.4 |
|
| Entergy Louisiana | $950.3 | |
| $1.9 |
| |
| $51.0 |
| |
| $24.7 |
| |
| $— |
| |
| $1,027.9 |
|
| $1,027.9 |
| |
| $— |
| |
| $54.8 |
| |
| $— |
| |
| $— |
| |
| $1,082.7 |
|
| Entergy Mississippi | $6.8 | |
| $1.1 |
| |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $8.3 |
|
| $8.3 |
| |
| $— |
| |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $8.7 |
|
| Entergy New Orleans | $2.5 | |
| $— |
| |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $2.7 |
|
| $2.7 |
| |
| $— |
| |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $2.9 |
|
| Entergy Texas | $4.6 | |
| $1.4 |
| |
| $0.3 |
| |
| ($0.2 | ) | |
| $— |
| |
| $6.1 |
|
| $6.1 |
| |
| $— |
| |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $6.5 |
|
| System Energy | $757.9 | |
| $— |
| |
| $48.0 |
| |
| ($2.5 | ) | |
| $— |
| |
| $803.4 |
|
| $803.4 |
| |
| $— |
| |
| $50.8 |
| |
| $— |
| |
| $— |
| |
| $854.2 |
|
| Entergy Wholesale Commodities | $1,917.8 | |
| $— |
| |
| $153.8 |
| |
| $99.6 |
| |
| ($101.7 | ) | |
| $2,069.5 |
| |
| Entergy Wholesale Commodities: | |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Big Rock Point | |
| $28.0 |
| |
| $— |
| |
| $2.2 |
| |
| $10.1 |
| |
| ($2.4 | ) | |
| $37.9 |
|
| FitzPatrick | |
| $— |
| |
| $696.2 |
| (b) |
| $18.1 |
| |
| $— |
| |
| $— |
| |
| $714.3 |
|
| Indian Point 1 | |
| $197.9 |
| |
| $— |
| |
| $17.1 |
| |
| ($0.3 | ) | |
| ($7.1 | ) | |
| $207.6 |
|
| Indian Point 2 | |
| $390.1 |
| |
| $— |
| |
| $33.0 |
| |
| $230.0 |
| |
| $— |
| |
| $653.1 |
|
| Indian Point 3 | |
| $— |
| |
| $466.3 |
| (b) |
| $12.1 |
| |
| $162.7 |
| |
| $— |
| |
| $641.1 |
|
| Palisades | |
| $342.0 |
| |
| $— |
| |
| $29.5 |
| |
| $128.8 |
| |
| $— |
| |
| $500.3 |
|
| Pilgrim | |
| $551.2 |
| |
| $— |
| |
| $48.4 |
| |
| $3.2 |
| |
| ($0.5 | ) | |
| $602.3 |
|
| Vermont Yankee | |
| $560.0 |
| |
| $— |
| |
| $39.3 |
| |
| $— |
| |
| ($128.8 | ) | |
| $470.5 |
|
| Other (c) | |
| $0.3 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $0.3 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Liabilities as of December 31, 2014 | | Liabilities Incurred | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2015 |
| | (In Millions) |
| Utility: | | | | | | | | | | | |
| Entergy Arkansas |
| $818.4 |
| |
| $3.5 |
| (c) |
| $50.4 |
| |
| $— |
| |
| $— |
| |
| $872.3 |
|
| Entergy Louisiana |
| $950.3 |
| |
| $1.9 |
| (c) |
| $51.0 |
| |
| $24.7 |
| |
| $— |
| |
| $1,027.9 |
|
| Entergy Mississippi |
| $6.8 |
| |
| $1.1 |
| (c) |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $8.3 |
|
| Entergy New Orleans |
| $2.5 |
| |
| $— |
| |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $2.7 |
|
| Entergy Texas |
| $4.6 |
| |
| $1.4 |
| (c) |
| $0.3 |
| |
| ($0.2 | ) | |
| $— |
| |
| $6.1 |
|
| System Energy |
| $757.9 |
| |
| $— |
| |
| $48.0 |
| |
| ($2.5 | ) | |
| $— |
| |
| $803.4 |
|
| Entergy Wholesale Commodities: |
|
| |
|
| |
|
| |
|
| |
|
| |
|
|
| Big Rock Point |
| $27.8 |
| |
| $— |
| |
| $2.2 |
| |
| $— |
| |
| ($2.0 | ) | |
| $28.0 |
|
| Indian Point 1 |
| $188.9 |
| |
| $— |
| |
| $16.3 |
| |
| $— |
| |
| ($7.3 | ) | |
| $197.9 |
|
| Indian Point 2 |
| $359.7 |
| |
| $— |
| |
| $30.4 |
| |
| $— |
| |
| $— |
| |
| $390.1 |
|
| Palisades |
| $352.0 |
| |
| $— |
| |
| $25.2 |
| |
| ($35.2 | ) | |
| $— |
| |
| $342.0 |
|
| Pilgrim |
| $383.1 |
| |
| $— |
| |
| $33.3 |
| |
| $134.8 |
| |
| $— |
| |
| $551.2 |
|
| Vermont Yankee |
| $606.3 |
| |
| $— |
| |
| $46.1 |
| |
| $— |
| |
| ($92.4 | ) | |
| $560.0 |
|
| Other (c) |
| $— |
| |
| $— |
| |
| $0.3 |
| |
| $— |
| |
| $— |
| |
| $0.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Entergy Wholesale Commodities includes $714.3 million of asset retirement obligation for FitzPatrick which is classified as held for sale within other non-current liabilities on the consolidated balance sheet. See Note 14 to the financial statements for discussion of the agreement to sell the FitzPatrick plant to Exelon. |
| |
| (b) | See “Entergy Wholesale Commodities” in “Nuclear Plant Decommissioning” below for additional discussion regarding the decommissioning agreements with NYPA and the associated asset retirement obligations. |
| |
| (c) | See “Coal Combustion Residuals” below for additional discussion regarding the asset retirement obligations related to coal combustion residuals management. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The cumulative decommissioning and retirement cost liabilities and expenses recorded in 2014 by Entergy were as follows:
|
| | | | | | | | | | | | | | | | | | | |
| | Liabilities as of December 31, 2013 | | Accretion | | Change in Cash Flow Estimate | | Spending | | Liabilities as of December 31, 2014 |
| | (In Millions) |
| Utility: | | | | | | | | | |
| Entergy Arkansas |
| $723.8 |
| |
| $47.0 |
| |
| $47.6 |
| |
| $— |
| |
| $818.4 |
|
| Entergy Louisiana |
| $882.2 |
| |
| $48.1 |
| |
| $20.0 |
| |
| $— |
| |
| $950.3 |
|
| Entergy Mississippi |
| $6.4 |
| |
| $0.4 |
| |
| $— |
| |
| $— |
| |
| $6.8 |
|
| Entergy New Orleans |
| $2.3 |
| |
| $0.2 |
| |
| $— |
| |
| $— |
| |
| $2.5 |
|
| Entergy Texas |
| $4.3 |
| |
| $0.3 |
| |
| $— |
| |
| $— |
| |
| $4.6 |
|
| System Energy |
| $616.2 |
| |
| $41.8 |
| |
| $99.9 |
| |
| $— |
| |
| $757.9 |
|
| Entergy Wholesale Commodities |
| $1,698.2 |
| |
| $139.7 |
| |
| $101.6 |
| |
| ($21.7 | ) | |
| $1,917.8 |
|
Nuclear Plant Decommissioning
Entergy periodically reviews and updates estimated decommissioning costs. The actual decommissioning costs may vary from the estimates because of the timing of plant decommissioning, regulatory requirements, changes in technology, and increased costs of labor, materials, and equipment. As described below, during 20152016 and 20142015, Entergy updated decommissioning cost estimates for certain nuclear power plants.
In the second quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for a nuclear site as a result of a revised decommissioning cost study. The revised estimate resulted in a $77.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.
In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Pilgrim as a result of a revised decommissioning cost study. The revised estimate resulted in a $134 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant no later than June 2019. The asset retirement cost asset was included in the Pilgrim carrying value that was written down to fair value in the third quarter 2015. See Note 1 to the financial statements for discussion of the impairment of the value and planned shutdown of the Pilgrim plant.
After shutdown, Pilgrim will transition to decommissioning. The Pilgrim nuclear decommissioning trust had a balance of approximately $896 million as of December 31, 2015, representing excess financial assurance of approximately $270 million for license termination activities above NRC-required assurance levels. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation. No additional funding is anticipated at this time.Utility
In the fourth quarter 2015, 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 $24.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In the fourth quarter 2015, 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 $2.5 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the fourth quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $42.4 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2015. See Note 1 to the financial statements for discussion of the impairment of the value of the Palisades plant.
In 2013, Entergy Wholesale Commodities recorded two revisions to its estimated decommissioning cost liability for Vermont Yankee. In the third quarterAugust 2013 the estimated decommissioning cost liability increased by $58 million, along withBoard approved a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows dueplan to the decision to cease operations of the plant. The asset retirement cost asset was included in the carrying value used to write downclose and decommission Vermont Yankee and related assets to their fair values inat the third quarter 2013.end of 2014. As a result of the settlement agreement regardingentered into by Entergy and the remaining operation and decommissioningstate of Vermont, Yankee, Entergy reassessed its assumptions regarding the timing of decommissioning cash flows. The reassessment resulted in a $27.2 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in fourth quarter 2013.
In accordance with the settlement agreement, Entergy Vermont Yankee provided to the Vermont parties, in 2014, a site assessment study of the costs and tasks of radiological decommissioning, spent nuclear fuel management, and site restoration for Vermont Yankee. Entergy Vermont Yankee filed its Post-Shutdown Decommissioning Activities Report (PSDAR) for Vermont Yankee with the NRC in December 2014. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014.
Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Filings with the NRC for planned shutdown activities will determine whether any other financial assurance may be required and will specifically address funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation.
Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover Vermont Yankee’s expected costs of decommissioning, spent fuel management costs, and site restoration. In June 2015 the NRC staff issued an exemption
Entergy Corporation and Subsidiaries
Notes to Financial Statements
from its regulations to allow Vermont Yankee to use its decommissioning trust fund to pay for approximately $225 million of estimated future spent fuel management costs that will not be paid for using funds from the credit facilities. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. IfIn February 2016 the appeal werecourt dismissed the petition as premature because Vermont and the utilities had requested the NRC to result inreconsider a final decision denyingnumber of issues related to Vermont Yankee the exemption allowing theYankee's use of itsthe decommissioning trust fund including its use to pay for these spent fuel management costs, Vermont Yankee would haveexpenses pursuant to satisfythe exemption granted in June 2015. In October 2016 the NRC that it haddenied Vermont's and the utilities' request for a planhearing and other relief but directed the NRC staff to obtain additional funds to enable it to pay for these costs untilconduct an assessment of any environmental impacts associated with the federal government takes possession of the fuel and removes it from the site. See Note 1 to the financial statements for further discussion regarding the Vermont Yankee plant.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets that will be depreciated over the remaining lives of the units.exemption.
In the fourthsecond quarter 2014,2015, Entergy LouisianaWholesale Commodities recorded a revision to its estimated decommissioning cost liability for River BendPalisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $20$77.6 million reduction in the decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset.
In the fourth quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Palisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $42.4 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows. The asset retirement cost asset was included in the Palisades carrying value that will be depreciated overwas written down to fair value in the remaining useful life of the unit.fourth quarter 2015.
In the fourth quarter 2014, System Energy2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Grand GulfPalisades as a result of a revised decommissioning cost study. The revised estimate resulted in a $99.9$129 million increase in itsthe decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated overasset. The increase in the remaining lifeestimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the unit.plant on October 1, 2018, subject to regulatory approval. The asset retirement cost asset was included in the Palisades carrying value that was written down to fair value in the fourth quarter 2016. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Palisades plant.
In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liability for Pilgrim as a result of a revised decommissioning cost study. The revised estimate resulted in a $134 million increase in the decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset. The increase in the estimated decommissioning cost liability resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the plant no later than June 2019. The asset retirement cost asset was included in the Pilgrim carrying value that was written down to fair value in the third quarter 2015. See Note 14 to the financial statements for discussion of the impairment of the value and planned shutdown of the Pilgrim plant.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning truststrust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specifyspecified their decommissioning obligations. NYPA hashad the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assignsassigned the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. IfUnder the original agreements, if the decommissioning liabilities arewere retained by NYPA, the Entergy subsidiaries willwould 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. Thetrust funds. At the time of the acquisition of the plants Entergy recorded a contract asset representsthat represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. The asset iswas 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 iswas recorded as interest income.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
In the third quarter 2015, Entergy Wholesale Commodities recorded a revision to the contract asset for the FitzPatrick plant. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. As a result of the agreement with NYPA, in the third quarter 2016 Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and asset retirement obligations for the decommissioning liabilities. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017.
In the fourth quarter 2016, Entergy Wholesale Commodities recorded a revision to its estimated decommissioning cost liabilities for Indian Point 1, Indian Point 2, and Indian Point 3 as a result of revised decommissioning cost studies. The revised estimates resulted in a $392 million increase in the decommissioning cost liabilities, along with a corresponding increase in the related asset retirement cost assets. The increase in the estimated decommissioning cost liabilities resulted from the change in expectation regarding the timing of decommissioning cash flows due to the decision to cease operations of the Indian Point 2 plant no later than April 2020 and the Indian Point 3 plant no later than April 2021. The asset retirement cost assets were included in the carrying value that was written down to fair value in the fourth quarter 2016. See Note 114 to the financial statements for further discussion of the impairment of the value and planned shutdown of the FitzPatrick plant.Indian Point Energy Center.
As the Entergy Wholesale Commodities nuclear plants individually transition to decommissioning, the Entergy Wholesale Commodities plant owners will submit filings with the NRC for planned shutdown activities. These filings with the NRC will determine whether any other financial assurance may be required. The plants’ owners are required to provide the NRC with a biennial report (annually for units that have shut down or will shut down within five years), based on values as of December 31, 2015addressing the contract asset forowners’ ability to meet the Indian Point 3NRC minimum funding levels. Depending on the value of the trust funds, the Entergy Wholesale Commodities plant owners may be required to take steps, such as providing financial guarantees through letters of credit or parent company guarantees or making additional contributions to the trusts, which could be significant, to ensure that the trusts are adequately funded and FitzPatrick plants is $420.8 million.that NRC minimum funding requirements are met.
Entergy maintains decommissioning trust funds that are committed to meeting its obligations for 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, 2016 and 2015 are as follows:
| | | | | | | | 2016 | | 2015 |
| | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) | | Decommissioning
Trust Fair Values | | Regulatory
Asset (Liability) |
| | (In Millions) | (In Millions) | | (In Millions) |
| Utility: | | | | | | | | | | |
| ANO 1 and ANO 2 |
| $771.3 |
| |
| $280.3 |
|
| $834.7 |
| | $316.3 | |
| $771.3 |
| |
| $280.3 |
|
| River Bend |
| $651.7 |
| |
| ($26.8 | ) |
| $712.8 |
| | ($28.4) | |
| $651.7 |
| |
| ($26.8 | ) |
| Waterford 3 |
| $390.6 |
| |
| $158.5 |
|
| $427.9 |
| | $172.8 | |
| $390.6 |
| |
| $158.5 |
|
| Grand Gulf |
| $701.5 |
| |
| $108.6 |
|
| $780.5 |
| | $142.5 | |
| $701.5 |
| |
| $108.6 |
|
| Entergy Wholesale Commodities |
| $2,834.9 |
| |
| $— |
|
| $2,968.0 |
| | $— | |
| $2,834.9 |
| |
| $— |
|
As a result of the agreement with NYPA discussed above, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables of $1.5 billion for the beneficial interests in the decommissioning trust funds for Indian Point 3 and FitzPatrick. At December 31, 2016, the fair values of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values ofare based on the trust statements received from NYPA and are valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value hierarchy. The receivables for the beneficial interests in the decommissioning trust funds andare recorded in other deferred debits on the related asset retirement obligation regulatory assets (liabilities) of Entergy as of December 31, 2014 are as follows:
|
| | | | | | | |
| | Decommissioning Trust Fair Values | | Regulatory Asset (Liability) |
| | (In Millions) |
| Utility: | | | |
| ANO 1 and ANO 2 |
| $769.9 |
| |
| $247.6 |
|
| River Bend |
| $637.7 |
| |
| ($25.5 | ) |
| Waterford 3 |
| $383.6 |
| |
| $145.5 |
|
| Grand Gulf |
| $679.8 |
| |
| $80.4 |
|
| Entergy Wholesale Commodities |
| $2,899.9 |
| |
| $— |
|
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained 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 reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D. The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. In December 2016, the Water Infrastructure Improvements for the Nation Act was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for permit programs. Entergy is monitoring state agency actions and will participate in the regulatory development process.
NOTE 10. LEASES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
General
As of December 31, 2015,2016, Entergy had capital leases and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions, all of which are discussed elsewhere):
| | Year | | Operating Leases | | Capital Leases | | Operating Leases | | Capital Leases |
| | | (In Thousands) | | (In Thousands) |
| 2016 | |
| $78,302 |
| |
| $4,694 |
| |
| 2017 | | 64,371 |
| | 4,694 |
| |
| $76,663 |
| |
| $4,694 |
|
| 2018 | | 53,073 |
| | 3,909 |
| | 69,620 |
| | 3,255 |
|
| 2019 | | 50,574 |
| | 3,124 |
| | 67,218 |
| | 3,124 |
|
| 2020 | | 33,337 |
| | 3,065 |
| | 51,127 |
| | 3,065 |
|
| 2021 | | | 41,531 |
| | 2,887 |
|
| Years thereafter | | 79,662 |
| | 24,778 |
| | 90,787 |
| | 21,891 |
|
| Minimum lease payments | | 359,319 |
| | 44,264 |
| | 396,946 |
| | 38,916 |
|
| Less: Amount representing interest | | — |
| | 13,918 |
| | — |
| | 11,934 |
|
| Present value of net minimum lease payments | |
| $359,319 |
| |
| $30,346 |
| |
| $396,946 |
| |
| $26,982 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total rental expenses for all leases (excluding power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions) amounted to $44.4 million in 2016, $63.9 million in 2015, and $59 million in 2014, and $63.7 million in 2013.2014.
As of December 31, 20152016 the Registrant Subsidiaries had a capital lease and non-cancelable operating leases for equipment, buildings, vehicles, and fuel storage facilities with minimum lease payments as follows (excluding
Entergy Corporation and Subsidiaries
Notes to Financial Statements
power purchase agreement operating leases, nuclear fuel leases, and the Grand Gulf and Waterford 3 sale and leaseback transactions,lease obligations, all of which are discussed elsewhere):
Capital Leases
| | Year | | Entergy Mississippi | | Entergy Mississippi |
| | | (In Thousands) | | (In Thousands) |
| 2016 | |
| $1,570 |
| |
| 2017 | | 1,570 |
| |
| $1,570 |
|
| 2018 | | 785 |
| | 131 |
|
| 2019 | | — |
| | — |
|
| 2020 | | — |
| | — |
|
| 2021 | | | — |
|
| Years thereafter | | — |
| | — |
|
| Minimum lease payments | | 3,925 |
| | 1,701 |
|
| Less: Amount representing interest | | 329 |
| | 111 |
|
| Present value of net minimum lease payments | |
| $3,596 |
| |
| $1,590 |
|
Operating Leases
| | Year | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| 2016 | |
| $25,358 |
| |
| $16,757 |
| |
| $7,139 |
| |
| $1,960 |
| |
| $5,700 |
| |
| 2017 | | 18,600 |
| | 14,245 |
| | 5,596 |
| | 1,730 |
| | 4,841 |
| |
| $17,648 |
| |
| $23,947 |
| |
| $8,014 |
| |
| $2,324 |
| |
| $5,361 |
|
| 2018 | | 12,947 |
| | 12,187 |
| | 4,946 |
| | 1,416 |
| | 4,302 |
| | 14,667 |
| | 22,053 |
| | 7,171 |
| | 2,065 |
| | 4,882 |
|
| 2019 | | 13,555 |
| | 12,677 |
| | 4,619 |
| | 1,233 |
| | 3,194 |
| | 15,419 |
| | 22,461 |
| | 6,830 |
| | 1,882 |
| | 3,841 |
|
| 2020 | | 7,029 |
| | 7,107 |
| | 3,710 |
| | 1,003 |
| | 1,666 |
| | 8,871 |
| | 16,700 |
| | 5,878 |
| | 1,627 |
| | 2,335 |
|
| 2021 | | | 6,697 |
| | 12,097 |
| | 4,200 |
| | 1,218 |
| | 1,546 |
|
| Years thereafter | | 28,390 |
| | 6,903 |
| | 6,028 |
| | 1,733 |
| | 1,695 |
| | 25,818 |
| | 22,966 |
| | 5,865 |
| | 1,864 |
| | 2,009 |
|
| Minimum lease payments | |
| $105,879 |
| |
| $69,876 |
| |
| $32,038 |
| |
| $9,075 |
| |
| $21,398 |
| |
| $89,120 |
| |
| $120,224 |
| |
| $37,958 |
| |
| $10,980 |
| |
| $19,974 |
|
Rental Expenses
| | Year | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Millions) | | (In Millions) |
| 2016 | | |
| $8.0 |
| |
| $17.8 |
| |
| $4.0 |
| |
| $0.9 |
| |
| $2.8 |
| |
| $1.6 |
|
| 2015 | |
| $13.6 |
| |
| $21.8 |
| |
| $5.4 |
| |
| $1.6 |
| |
| $4.0 |
| |
| $2.9 |
| |
| $13.6 |
| |
| $21.8 |
| |
| $5.4 |
| |
| $1.6 |
| |
| $4.0 |
| |
| $2.9 |
|
| 2014 | |
| $12.0 |
| |
| $20.7 |
| |
| $4.3 |
| |
| $1.2 |
| |
| $3.8 |
| |
| $2.0 |
| |
| $12.0 |
| |
| $20.7 |
| |
| $4.3 |
| |
| $1.2 |
| |
| $3.8 |
| |
| $2.0 |
|
| 2013 | |
| $12.0 |
| |
| $21.0 |
| |
| $4.6 |
| |
| $1.3 |
| |
| $4.1 |
| |
| $2.5 |
| |
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 $3.4 million in 2016, $4.7 million in 2015, and $4.8 million in 2014 for Entergy Arkansas and $0.3 million in 2016, $1.1 million in 2015, and $1.7 million in 2014 for Entergy Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2016, $1.6 million in 2015, and $1.6 million in 2014.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
in 2015, $4.8 million in 2014, and $8.6 million in 2013 for Entergy Arkansas and $1.1 million in 2015, $1.7 million in 2014, and $2.2 million in 2013 for Entergy Louisiana. Oil tank facilities lease payments for Entergy Mississippi were $1.6 million in 2015, $1.6 million in 2014, and $3.4 million in 2013.
Power Purchase Agreements
As of December 31, 2015,2016, Entergy Texas had a power purchase agreement that is accounted for as an operating lease under the accounting standards. The lease payments are recovered in fuel expense in accordance with regulatory treatment. The minimum lease payments under the power purchase agreement are as follows:
| | | Year | | Entergy Texas (a) | | Entergy | | Entergy Texas (a) | | Entergy |
| | | (In Thousands) | | (In Thousands) |
| 2016 | |
| $29,104 |
| |
| $29,104 |
| |
| 2017 | | 29,772 |
| | 29,772 |
| |
| $29,772 |
| |
| $29,772 |
|
| 2018 | | 30,458 |
| | 30,458 |
| | 30,458 |
| | 30,458 |
|
| 2019 | | 31,159 |
| | 31,159 |
| | 31,159 |
| | 31,159 |
|
| 2020 | | 31,876 |
| | 31,876 |
| | 31,876 |
| | 31,876 |
|
| 2021 | | | 32,609 |
| | 32,609 |
|
| Years thereafter | | 42,789 |
| | 42,789 |
| | 10,180 |
| | 10,180 |
|
| Minimum lease payments | |
| $195,158 |
| |
| $195,158 |
| |
| $166,054 |
| |
| $166,054 |
|
| |
| (a) | Amounts reflect 100% of minimum payments. Under a separate contract, Entergy Louisiana purchases 50% of the capacity and energy from the power purchase agreement from Entergy Texas. |
Total capacity expense under the power purchase agreement accounted for as an operating lease at Entergy Texas was $26.1 million in 2016, $29.9 million in 2015, and $29.2 million in 2014, and $28.6 million in 2013.2014.
SaleSales and Leaseback Transactions
Waterford 3 Lease ObligationsObligation
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 leases expire in July 2017. Entergy Louisiana is required to report the sale-leaseback as a financing transaction in its financial statements.
In December 2015, Entergy Louisiana agreed to purchase the undivided interests in Waterford 3 that are currentlywere previously being leased. The purchase will bewas accomplished in a two-step transaction in which Entergy Louisiana will first acquireacquired the equity participant’s beneficial interest in the leased assets, followed by a termination of the leases and transfer of the leased assets to Entergy Louisiana when the outstanding lessor debt is paid.
The purchase price will be approximately $112 million, of whichIn March 2016, Entergy Louisiana completed the first step in the two-step transaction by acquiring the equity participant’s beneficial interest in the leased assets. Entergy Louisiana paid $60 million will be paid in cash and the remaining approximately $52 million will be paid through the issuance of a non-interest bearing collateral trust mortgage bond,note, payable in installments through July 2017. The $60 million cash payment represents the purchase price to acquire the undivided interests in the plant. Following the purchase, Entergy Louisiana will also continuecontinued to make payments on the lessor debt that remained outstanding and which remains outstanding.matured in January 2017. The combination of payments due on the approximately $52 million collateral trust mortgage bondnote issued and the debt service on the lessor debt areis equal in timing and amount to the remaining lease payments due from the expected closing of the transaction through the remainderend of the lease term. Therefore, this transaction will not change the total amount of debt outstanding on Entergy Louisiana’s financial statements related to the Waterford 3 sale-leaseback. Payments include $7.8 millionterm in July 2016 and $106.3 million in 2017. An additional lease payment of $9.2 million was made in January 2016, prior to the closing of this transaction. In February 2016 the FERC authorized
Entergy Corporation and Subsidiaries
Notes to Financial Statements
the transaction. Consummation of the transaction is subject to customary closing conditions, and is expected to close in the first half of 2016.
Throughout the term of the lease, Entergy Louisiana had accrued a liability for the amount it expected to pay to retain the use of the undivided interests in Waterford 3 at the end of the lease term. Since the sale-leaseback transaction was accounted for as a financing transaction, the accrual of this liability was accounted for as additional interest expense. As of December 2015, the balance of this liability was $62.7 million. Upon entering into the agreement to purchase the equity participant’s beneficial interest in the undivided interests, Entergy Louisiana reduced the balance of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
liability to $60 million, and recorded the $2.7 million difference as a credit to interest expense. The $60 million remaining liability will bewas eliminated upon payment of the cash portion of the purchase price.
Entergy Louisiana had previously issued $193.2 million of non-interest bearing first mortgage bonds as collateral for the equity portion of certain amounts payable under the leases. Upon the acquisition of the beneficial interests described above, these mortgage bonds will be surrendered for cancellation.
The lease transaction documents provide that, 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 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 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, 2015, Entergy Louisiana was in compliance with these provisions.
As of December 31, 2015,2016, Entergy Louisiana, in connection with the Waterford 3 sale and leaseback transactions,lease obligation, had a future minimum lease paymentspayment (reflecting an overall implicitinterest rate of 7.45%, and which include the equity portion8.09%) of lease payments which will, upon the acquisition of the beneficial interests, be payable under the mortgage bond described above)$57.5 million, including $2.3 million in interest, due January 2017 that areis recorded as long-term debt, as follows:debt.
|
| | | |
| | Amount |
| | (In Thousands) |
| | |
| 2016 |
| $16,938 |
|
| 2017 | 106,335 |
|
| 2018 | — |
|
| 2019 | — |
|
| 2020 | — |
|
| Years thereafter | — |
|
| Total | 123,273 |
|
| Less: Amount representing interest | 14,308 |
|
| Present value of net minimum lease payments |
| $108,965 |
|
Grand Gulf Lease Obligations
In 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 initial term of the leases expired in July 2015. System Energy renewed the leases for fair market value with renewal terms expiring in July 2036. At the end of the new lease renewal terms, System Energy has the option to repurchase the leased interests in Grand Gulf or renew the leases at fair market value. In the event that System Energy does not renew or purchase the interests, System Energy would surrender such interests and their associated entitlement of Grand Gulf’s capacity and energy.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 $55.6 million and $62.9$55.6 million as of December 31, 20152016 and 2014,2015, respectively.
As of December 31, 2015,2016, System Energy, in connection with the Grand Gulf sale and leaseback transactions, had future minimum lease payments (reflecting an implicit rate of 5.13%) that are recorded as long-term debt, as follows:
| | | | Amount | Amount |
| | (In Thousands) | (In Thousands) |
| | | |
| 2016 |
| $17,188 |
| |
| 2017 | 17,188 |
|
| $17,188 |
|
| 2018 | 17,188 |
| 17,188 |
|
| 2019 | 17,188 |
| 17,188 |
|
| 2020 | 17,188 |
| 17,188 |
|
| 2021 | | 17,188 |
|
| Years thereafter | 275,000 |
| 257,812 |
|
| Total | 360,940 |
| 343,752 |
|
| Less: Amount representing interest | 326,579 |
| 309,393 |
|
| Present value of net minimum lease payments |
| $34,361 |
|
| $34,359 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 11. RETIREMENT, OTHER POSTRETIREMENT BENEFITS, AND DEFINED CONTRIBUTION PLANS (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Qualified Pension Plans
Entergy has nine qualified pension plans covering substantially all employees. The “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Retirement Plan II for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan II for Bargaining Employees,” “Entergy Corporation Retirement Plan III,” “Entergy Corporation Retirement Plan IV for Non-Bargaining Employees,” and “Entergy Corporation Retirement Plan IV for Bargaining Employees” are non-contributory final average pay plans and provide pension benefits that are based on employees’ credited service and compensation during employment. The “EntergyEffective December 31, 2016, the Entergy Corporation Retirement Plan III”IV for Non-Bargaining Employees was merged with and into the Entergy Corporation Retirement Plan II for Non-Bargaining Employees. There is no loss of vesting or benefit options or reduction of accrued benefits to affected participants as a final average payresult of this plan that provides pension benefits that are based on employees’ credited service and compensation during the final years before retirement and 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.merger. Non-bargaining employees whose most recent date of hire is after June 30, 2014 participate in the “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees.” Certain bargaining employees hired or rehired after June 30, 2014, or such later date provided for in their applicable collective bargaining agreements, participate in the “Entergy Corporation Cash Balance Plan for Bargaining Employees.” The Registrant Subsidiaries participate in these four plans: “Entergy Corporation Retirement Plan for Non-Bargaining Employees,” “Entergy Corporation Retirement Plan for Bargaining Employees,” “Entergy Corporation Cash Balance Plan for Non-Bargaining Employees,” and “Entergy Cash Balance Plan for Bargaining Employees.”
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The assets of the seven final average pay qualified pension plans are held in a master trust established by Entergy, and the assets of the two cash balance pension plans are held in a second master trust established by Entergy. Each pension plan has an undivided beneficial interest in each of the investment accounts in its respective master trust that is maintained by a trustee. Use of the master trusts 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 in the master trusts are commingled, the trustee maintains supporting records for the purpose of allocating the trust level equity in net earnings (loss) and the administrative expenses of the investment accounts in each trust to the various participating pension plans in that particular trust. The fair value of the trusts’ assets is determined by the trustee and certain investment managers. For each trust, 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 trusts on a pro rata basis.
Within each pension plan, the record of each Registrant Subsidiary’s beneficial interest in the plan assets is maintained by the plan’s actuary and is updated quarterly. Assets for each Registrant Subsidiary are increased for investment net income and contributions, and are decreased for benefit payments. A plan’s investment net income/loss (i.e. interest and dividends, realized and unrealized gains and losses and 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 plans in an amount not less than the minimum required contribution under 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’ pension costs are recovered from customers as a component of cost of service in each of their respective jurisdictions.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Components of Qualified Net Pension Cost and Other Amounts Recognized as a Regulatory Asset and/or Accumulated Other Comprehensive Income (AOCI)
Entergy Corporation and its subsidiaries’ total 2016, 2015, 2014, and 20132014 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, included the following components:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Net periodic pension cost: | |
| | |
| | |
| |
| | |
| | |
|
| Service cost - benefits earned during the period |
| $175,046 |
| |
| $140,436 |
| |
| $172,280 |
|
| $143,244 |
| |
| $175,046 |
| |
| $140,436 |
|
| Interest cost on projected benefit obligation | 302,777 |
| | 290,076 |
| | 263,296 |
| 261,613 |
| | 302,777 |
| | 290,076 |
|
| Expected return on assets | (394,618 | ) | | (361,462 | ) | | (328,227 | ) | (389,465 | ) | | (394,618 | ) | | (361,462 | ) |
| Amortization of prior service cost | 1,561 |
| | 1,600 |
| | 2,125 |
| 1,079 |
| | 1,561 |
| | 1,600 |
|
| Recognized net loss | 235,922 |
| | 145,095 |
| | 213,194 |
| 195,298 |
| | 235,922 |
| | 145,095 |
|
| Curtailment loss | 374 |
| | — |
| | 16,318 |
| 3,084 |
| | 374 |
| | — |
|
| Special termination benefit | 76 |
| | 732 |
| | 13,139 |
| — |
| | 76 |
| | 732 |
|
| Net periodic pension costs |
| $321,138 |
| |
| $216,477 |
| |
| $352,125 |
|
| $214,853 |
| |
| $321,138 |
| |
| $216,477 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | |
| Arising this period: | | | | | | | | | | |
| Net (gain)/loss |
| $50,762 |
| |
| $1,389,912 |
| |
| ($894,150 | ) | |
| Net loss | |
| $203,229 |
| |
| $50,762 |
| |
| $1,389,912 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | |
| Amortization of prior service cost | (1,561 | ) | | (1,600 | ) | | (2,125 | ) | (1,079 | ) | | (1,561 | ) | | (1,600 | ) |
| Acceleration of prior service cost to curtailment | (374 | ) | | — |
| | (1,307 | ) | (1,045 | ) | | (374 | ) | | — |
|
| Amortization of net loss | (235,922 | ) | | (145,095 | ) | | (213,194 | ) | (195,298 | ) | | (235,922 | ) | | (145,095 | ) |
| Total |
| ($187,095 | ) | |
| $1,243,217 |
| |
| ($1,110,776 | ) |
| $5,807 |
| |
| ($187,095 | ) | |
| $1,243,217 |
|
| Total recognized as net periodic pension (income)/cost, regulatory asset, and/or AOCI (before tax) |
| $134,043 |
| |
| $1,459,694 |
| |
| ($758,651 | ) | |
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | |
| $220,660 |
| |
| $134,043 |
| |
| $1,459,694 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year: | | | | | | | | | | |
| Prior service cost |
| $1,079 |
| |
| $1,561 |
| |
| $1,600 |
|
| $261 |
| |
| $1,079 |
| |
| $1,561 |
|
| Net loss |
| $195,321 |
| |
| $237,013 |
| |
| $146,958 |
|
| $227,720 |
| |
| $195,321 |
| |
| $237,013 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Registrant Subsidiaries’ total 2016, 2015, 2014, and 20132014 qualified pension costs and amounts recognized as a regulatory asset and/or other comprehensive income, including amounts capitalized, for their employees included the following components:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $26,646 |
| |
| $34,396 |
| |
| $7,929 |
| |
| $3,395 |
| |
| $6,582 |
| |
| $7,827 |
| |
| $20,724 |
| |
| $28,194 |
| |
| $6,250 |
| |
| $2,625 |
| |
| $5,664 |
| |
| $6,263 |
|
| Interest cost on projected benefit obligation | | 61,885 |
| | 69,465 |
| | 18,007 |
| | 8,432 |
| | 17,414 |
| | 13,970 |
| | 52,219 |
| | 59,478 |
| | 15,245 |
| | 7,256 |
| | 14,228 |
| | 11,966 |
|
| Expected return on assets | | (80,102 | ) | | (90,803 | ) | | (24,420 | ) | | (10,899 | ) | | (24,887 | ) | | (18,271 | ) | | (79,087 | ) | | (88,383 | ) | | (23,923 | ) | | (10,748 | ) | | (24,248 | ) | | (17,836 | ) |
| Recognized net loss | | 54,254 |
| | 59,802 |
| | 14,896 |
| | 8,053 |
| | 12,950 |
| | 13,055 |
| | 43,745 |
| | 47,783 |
| | 11,938 |
| | 6,460 |
| | 9,358 |
| | 10,415 |
|
| Net pension cost | |
| $62,683 |
| |
| $72,860 |
| |
| $16,412 |
| |
| $8,981 |
| |
| $12,059 |
| |
| $16,581 |
| |
| $37,601 |
| |
| $47,072 |
| |
| $9,510 |
| |
| $5,593 |
| |
| $5,002 |
| |
| $10,808 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net (gain)/loss | |
| $16,687 |
| |
| $16,618 |
| |
| $6,329 |
| |
| $1,853 |
| |
| ($4,488 | ) | |
| $101 |
| |
| Net loss | | |
| $60,968 |
| |
| $46,742 |
| |
| $10,942 |
| |
| $5,463 |
| |
| $3,816 |
| |
| $20,805 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of net loss | | (54,254 | ) | | (59,802 | ) | | (14,896 | ) | | (8,053 | ) | | (12,950 | ) | | (13,055 | ) | | (43,745 | ) | | (47,783 | ) | | (11,938 | ) | | (6,460 | ) | | (9,358 | ) | | (10,415 | ) |
| Total | |
| ($37,567 | ) | |
| ($43,184 | ) | |
| ($8,567 | ) | |
| ($6,200 | ) | |
| ($17,438 | ) | |
| ($12,954 | ) | |
| $17,223 |
| |
| ($1,041 | ) | |
| ($996 | ) | |
| ($997 | ) | |
| ($5,542 | ) | |
| $10,390 |
|
| Total recognized as net periodic pension (income)/cost regulatory asset, and/or AOCI (before tax) | |
| $25,116 |
| |
| $29,676 |
| |
| $7,845 |
| |
| $2,781 |
| |
| ($5,379 | ) | |
| $3,627 |
| |
| $54,824 |
| |
| $46,031 |
| |
| $8,514 |
| |
| $4,596 |
| |
| ($540 | ) | |
| $21,198 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $43,747 |
| |
| $47,809 |
| |
| $11,938 |
| |
| $6,460 |
| |
| $9,358 |
| |
| $10,414 |
| |
| $46,560 |
| |
| $49,417 |
| |
| $12,213 |
| |
| $6,632 |
| |
| $9,241 |
| |
| $11,857 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $20,090 |
| |
| $25,706 |
| |
| $6,094 |
| |
| $2,666 |
| |
| $5,142 |
| |
| $5,785 |
| |
| $26,646 |
| |
| $34,396 |
| |
| $7,929 |
| |
| $3,395 |
| |
| $6,582 |
| |
| $7,827 |
|
| Interest cost on projected benefit obligation | | 59,537 |
| | 66,984 |
| | 17,273 |
| | 8,164 |
| | 17,746 |
| | 13,561 |
| | 61,885 |
| | 69,465 |
| | 18,007 |
| | 8,432 |
| | 17,414 |
| | 13,970 |
|
| Expected return on assets | | (73,218 | ) | | (83,746 | ) | | (22,794 | ) | | (10,019 | ) | | (23,723 | ) | | (16,619 | ) | | (80,102 | ) | | (90,803 | ) | | (24,420 | ) | | (10,899 | ) | | (24,887 | ) | | (18,271 | ) |
| Amortization of prior service cost | | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| |
| Recognized net loss | | 35,956 |
| | 40,446 |
| | 9,415 |
| | 5,796 |
| | 9,356 |
| | 9,500 |
| | 54,254 |
| | 59,802 |
| | 14,896 |
| | 8,053 |
| | 12,950 |
| | 13,055 |
|
| Net pension cost | |
| $42,365 |
| |
| $49,390 |
| |
| $9,988 |
| |
| $6,607 |
| |
| $8,521 |
| |
| $12,229 |
| |
| $62,683 |
| |
| $72,860 |
| |
| $16,412 |
| |
| $8,981 |
| |
| $12,059 |
| |
| $16,581 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $300,907 |
| |
| $318,932 |
| |
| $88,199 |
| |
| $38,161 |
| |
| $65,363 |
| |
| $60,763 |
| |
| $16,687 |
| |
| $16,618 |
| |
| $6,329 |
| |
| $1,853 |
| |
| ($4,488 | ) | |
| $101 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) | |
| Amortization of net loss | | (35,956 | ) | | (40,446 | ) | | (9,415 | ) | | (5,796 | ) | | (9,356 | ) | | (9,500 | ) | | (54,254 | ) | | (59,802 | ) | | (14,896 | ) | | (8,053 | ) | | (12,950 | ) | | (13,055 | ) |
| Total | |
| $264,951 |
| |
| $278,486 |
| |
| $78,784 |
| |
| $32,365 |
| |
| $56,007 |
| |
| $51,261 |
| |
| ($37,567 | ) | |
| ($43,184 | ) | |
| ($8,567 | ) | |
| ($6,200 | ) | |
| ($17,438 | ) | |
| ($12,954 | ) |
| Total recognized as net periodic pension cost, regulatory asset, and/or AOCI (before tax) | |
| $307,316 |
| |
| $327,876 |
| |
| $88,772 |
| |
| $38,972 |
| |
| $64,528 |
| |
| $63,490 |
| |
| $25,116 |
| |
| $29,676 |
| |
| $7,845 |
| |
| $2,781 |
| |
| ($5,379 | ) | |
| $3,627 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $54,254 |
| |
| $59,802 |
| |
| $14,896 |
| |
| $8,053 |
| |
| $12,950 |
| |
| $13,055 |
| |
| $43,747 |
| |
| $47,809 |
| |
| $11,938 |
| |
| $6,460 |
| |
| $9,358 |
| |
| $10,414 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2014 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Net periodic pension cost: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $25,229 |
| |
| $31,302 |
| |
| $7,295 |
| |
| $3,264 |
| |
| $6,475 |
| |
| $7,242 |
| |
| $20,090 |
| |
| $25,706 |
| |
| $6,094 |
| |
| $2,666 |
| |
| $5,142 |
| |
| $5,785 |
|
| Interest cost on projected benefit obligation | | 54,473 |
| | 61,598 |
| | 15,802 |
| | 7,462 |
| | 16,303 |
| | 12,170 |
| | 59,537 |
| | 66,984 |
| | 17,273 |
| | 8,164 |
| | 17,746 |
| | 13,561 |
|
| Expected return on assets | | (66,951 | ) | | (76,930 | ) | | (21,139 | ) | | (9,117 | ) | | (22,277 | ) | | (17,249 | ) | | (73,218 | ) | | (83,746 | ) | | (22,794 | ) | | (10,019 | ) | | (23,723 | ) | | (16,619 | ) |
| Amortization of prior service cost | | 23 |
| | 92 |
| | 10 |
| | 2 |
| | 6 |
| | 9 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 2 |
|
| Recognized net loss | | 49,517 |
| | 57,481 |
| | 13,189 |
| | 7,878 |
| | 13,302 |
| | 9,560 |
| | 35,956 |
| | 40,446 |
| | 9,415 |
| | 5,796 |
| | 9,356 |
| | 9,500 |
|
| Curtailment loss | | 4,938 |
| | 4,347 |
| | 767 |
| | 343 |
| | 1,559 |
| | — |
| |
| Special termination benefit | | 1,784 |
| | 2,439 |
| | 359 |
| | 581 |
| | 855 |
| | 1,970 |
| |
| Net pension cost | |
| $69,013 |
| |
| $80,329 |
| |
| $16,283 |
| |
| $10,413 |
| |
| $16,223 |
| |
| $13,702 |
| |
| $42,365 |
| |
| $49,390 |
| |
| $9,988 |
| |
| $6,607 |
| |
| $8,521 |
| |
| $12,229 |
|
| Other changes in plan assets and benefit obligations recognized as a regulatory asset and/or AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Arising this period: | | | | | | | | | | | | | | | | | | | | | | | | |
| Net gain | |
| ($177,105 | ) | |
| ($221,844 | ) | |
| ($52,525 | ) | |
| ($25,419 | ) | |
| ($55,772 | ) | |
| ($35,511 | ) | |
| $300,907 |
| |
| $318,932 |
| |
| $88,199 |
| |
| $38,161 |
| |
| $65,363 |
| |
| $60,763 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service cost | | (23 | ) | | (92 | ) | | (10 | ) | | (2 | ) | | (6 | ) | | (9 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | (2 | ) |
| Amortization of net loss | | (49,517 | ) | | (57,481 | ) | | (13,189 | ) | | (7,878 | ) | | (13,302 | ) | | (9,560 | ) | | (35,956 | ) | | (40,446 | ) | | (9,415 | ) | | (5,796 | ) | | (9,356 | ) | | (9,500 | ) |
| Total | |
| ($226,645 | ) | |
| ($279,417 | ) | |
| ($65,724 | ) | |
| ($33,299 | ) | |
| ($69,080 | ) | |
| ($45,080 | ) | |
| $264,951 |
| |
| $278,486 |
| |
| $78,784 |
| |
| $32,365 |
| |
| $56,007 |
| |
| $51,261 |
|
| Total recognized as net periodic pension income, regulatory asset, and/or AOCI (before tax) | |
| ($157,632 | ) | |
| ($199,088 | ) | |
| ($49,441 | ) | |
| ($22,886 | ) | |
| ($52,857 | ) | |
| ($31,378 | ) | |
| $307,316 |
| |
| $327,876 |
| |
| $88,772 |
| |
| $38,972 |
| |
| $64,528 |
| |
| $63,490 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service cost | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $2 |
| |
| Net loss | |
| $35,984 |
| |
| $40,295 |
| |
| $9,421 |
| |
| $5,802 |
| |
| $9,363 |
| |
| $9,510 |
| |
| $54,254 |
| |
| $59,802 |
| |
| $14,896 |
| |
| $8,053 |
| |
| $12,950 |
| |
| $13,055 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified PensionObligations, Plan Assets, Funded Status, Amounts Recognized in the Balance Sheet
Qualified pension obligations, plan assets, funded status, amounts recognized in the Consolidated Balance Sheets for Entergy Corporation and its Subsidiaries as of December 31, 2016 and 2015 and 2014are as follows:
| | | | December 31, | | | | | |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Change in Projected Benefit Obligation (PBO) | |
| | |
| |
| | |
|
| Balance at beginning of year |
| $7,230,542 |
| |
| $5,770,999 |
| |
| Balance at January 1 | |
| $6,848,238 |
| |
| $7,230,542 |
|
| Service cost | 175,046 |
| | 140,436 |
| 143,244 |
| | 175,046 |
|
| Interest cost | 302,777 |
| | 290,076 |
| 261,613 |
| | 302,777 |
|
| Curtailment | | 2,039 |
| | — |
|
| Special termination benefit | 76 |
| | 732 |
| — |
| | 76 |
|
| Actuarial (gain)/loss | (460,986 | ) | | 1,284,049 |
| 209,360 |
| | (460,986 | ) |
| Employee contributions | 524 |
| | 560 |
| 23 |
| | 524 |
|
| Benefits paid | (399,741 | ) | | (256,310 | ) | (321,950 | ) | | (399,741 | ) |
| Balance at end of year |
| $6,848,238 |
| |
| $7,230,542 |
| |
| Balance at December 31 | |
| $7,142,567 |
| |
| $6,848,238 |
|
| Change in Plan Assets | |
| | |
| |
| | |
|
| Fair value of assets at beginning of year |
| $4,827,966 |
| |
| $4,429,237 |
| |
| Fair value of assets at January 1 | |
| $4,707,433 |
| |
| $4,827,966 |
|
| Actual return on plan assets | (117,130 | ) | | 255,599 |
| 395,596 |
| | (117,130 | ) |
| Employer contributions | 395,814 |
| | 398,880 |
| 390,100 |
| | 395,814 |
|
| Employee contributions | 524 |
| | 560 |
| 23 |
| | 524 |
|
| Benefits paid | (399,741 | ) | | (256,310 | ) | (321,950 | ) | | (399,741 | ) |
| Fair value of assets at end of year |
| $4,707,433 |
| |
| $4,827,966 |
| |
| Fair value of assets at December 31 | |
| $5,171,202 |
| |
| $4,707,433 |
|
| Funded status |
| ($2,140,805 | ) | |
| ($2,402,576 | ) |
| ($1,971,365 | ) | |
| ($2,140,805 | ) |
| Amount recognized in the balance sheet | | | | | | |
| Non-current liabilities |
| ($2,140,805 | ) | |
| ($2,402,576 | ) |
| ($1,971,365 | ) | |
| ($2,140,805 | ) |
| Amount recognized as a regulatory asset | | | | | | |
| Prior service cost |
| $— |
| |
| $3,704 |
| |
| Net loss | 2,300,222 |
| | 2,451,172 |
|
| $2,326,349 |
| |
| $2,300,222 |
|
| |
| $2,300,222 |
| |
| $2,454,876 |
| |
| Amount recognized as AOCI (before tax) | | | | | | |
| Prior service cost |
| $2,784 |
| |
| $1,015 |
|
| $659 |
| |
| $2,784 |
|
| Net loss | 637,472 |
| | 671,682 |
| 619,276 |
| | 637,472 |
|
| |
| $640,256 |
| |
| $672,697 |
|
| $619,935 |
| |
| $640,256 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Qualified Pension Obligations, Plan Assets, Funded Status, and Amounts Recognizedpension obligations, plan assets, funded status, amounts recognized in the Balance SheetSheets for the Registrant Subsidiaries as of December 31, 2016 and 2015 and 2014are as follows:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | 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 | |
| $1,485,718 |
| |
| $1,666,535 |
| |
| $432,169 |
| |
| $202,555 |
| |
| $418,498 |
| |
| $334,312 |
| |
| Balance at January 1 | | |
| $1,400,511 |
| |
| $1,564,710 |
| |
| $408,604 |
| |
| $191,064 |
| |
| $383,627 |
| |
| $311,542 |
|
| Service cost | | 26,646 |
| | 34,396 |
| | 7,929 |
| | 3,395 |
| | 6,582 |
| | 7,827 |
| | 20,724 |
| | 28,194 |
| | 6,250 |
| | 2,625 |
| | 5,664 |
| | 6,263 |
|
| Interest cost | | 61,885 |
| | 69,465 |
| | 18,007 |
| | 8,432 |
| | 17,414 |
| | 13,970 |
| | 52,219 |
| | 59,478 |
| | 15,245 |
| | 7,256 |
| | 14,228 |
| | 11,966 |
|
| Actuarial gain | | (87,617 | ) | | (101,361 | ) | | (25,492 | ) | | (12,289 | ) | | (36,862 | ) | | (23,720 | ) | |
| Actuarial (gain)/loss | | | 62,187 |
| | 48,357 |
| | 11,343 |
| | 5,573 |
| | 4,274 |
| | 20,661 |
|
| Benefits paid | | (86,121 | ) | | (104,325 | ) | | (24,009 | ) | | (11,029 | ) | | (22,005 | ) | | (20,847 | ) | | (81,331 | ) | | (76,506 | ) | | (22,241 | ) | | (9,054 | ) | | (21,427 | ) | | (15,051 | ) |
| Balance at end of year | |
| $1,400,511 |
| |
| $1,564,710 |
| |
| $408,604 |
| |
| $191,064 |
| |
| $383,627 |
| |
| $311,542 |
| |
| Balance at December 31 | | |
| $1,454,310 |
| |
| $1,624,233 |
| |
| $419,201 |
| |
| $197,464 |
| |
| $386,366 |
| |
| $335,381 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $977,521 |
| |
| $1,113,359 |
| |
| $301,250 |
| |
| $133,344 |
| |
| $310,713 |
| |
| $217,621 |
| |
Fair value of assets at January 1 | | |
| $959,618 |
| |
| $1,071,234 |
| |
| $292,297 |
| |
| $129,975 |
| |
| $298,378 |
| |
| $212,006 |
|
| Actual return on plan assets | | (24,201 | ) | | (27,175 | ) | | (7,401 | ) | | (3,243 | ) | | (7,487 | ) | | (5,550 | ) | | 80,306 |
| | 89,998 |
| | 24,325 |
| | 10,858 |
| | 24,705 |
| | 17,692 |
|
| Employer contributions | | 92,419 |
| | 89,375 |
| | 22,457 |
| | 10,903 |
| | 17,157 |
| | 20,782 |
| | 82,999 |
| | 84,421 |
| | 19,968 |
| | 10,709 |
| | 15,920 |
| | 20,497 |
|
| Benefits paid | | (86,121 | ) | | (104,325 | ) | | (24,009 | ) | | (11,029 | ) | | (22,005 | ) | | (20,847 | ) | | (81,331 | ) | | (76,506 | ) | | (22,241 | ) | | (9,054 | ) | | (21,427 | ) | | (15,051 | ) |
| Fair value of assets at end of year | |
| $959,618 |
| |
| $1,071,234 |
| |
| $292,297 |
| |
| $129,975 |
| |
| $298,378 |
| |
| $212,006 |
| |
| Fair value of assets at December 31 | | |
| $1,041,592 |
| |
| $1,169,147 |
| |
| $314,349 |
| |
| $142,488 |
| |
| $317,576 |
| |
| $235,144 |
|
| Funded status | |
| ($440,893 | ) | |
| ($493,476 | ) | |
| ($116,307 | ) | |
| ($61,089 | ) | |
| ($85,249 | ) | |
| ($99,536 | ) | |
| ($412,718 | ) | |
| ($455,086 | ) | |
| ($104,852 | ) | |
| ($54,976 | ) | |
| ($68,790 | ) | |
| ($100,237 | ) |
| Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current liabilities | |
| ($440,893 | ) | |
| ($493,476 | ) | |
| ($116,307 | ) | |
| ($61,089 | ) | |
| ($85,249 | ) | |
| ($99,536 | ) | |
| ($412,718 | ) | |
| ($455,086 | ) | |
| ($104,852 | ) | |
| ($54,976 | ) | |
| ($68,790 | ) | |
| ($100,237 | ) |
| Amounts recognized as regulatory asset | | | | | | | | | | | | |
| | | | | | | | | | | | |
|
| Net loss | |
| $684,552 |
| |
| $687,305 |
| |
| $190,406 |
| |
| $95,941 |
| |
| $159,085 |
| |
| $159,508 |
| |
| $701,774 |
| |
| $686,337 |
| |
| $189,409 |
| |
| $94,944 |
| |
| $153,544 |
| |
| $169,897 |
|
| Amounts recognized as AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $— |
| |
| $51,733 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $51,660 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | 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 | |
| $1,192,640 |
| |
| $1,341,212 |
| |
| $345,824 |
| |
| $163,707 |
| |
| $356,080 |
| |
| $270,789 |
| |
| Balance at January 1 | | |
| $1,485,718 |
| |
| $1,666,535 |
| |
| $432,169 |
| |
| $202,555 |
| |
| $418,498 |
| |
| $334,312 |
|
| Service cost | | 20,090 |
| | 25,706 |
| | 6,094 |
| | 2,666 |
| | 5,142 |
| | 5,785 |
| | 26,646 |
| | 34,396 |
| | 7,929 |
| | 3,395 |
| | 6,582 |
| | 7,827 |
|
| Interest cost | | 59,537 |
| | 66,984 |
| | 17,273 |
| | 8,164 |
| | 17,746 |
| | 13,561 |
| | 61,885 |
| | 69,465 |
| | 18,007 |
| | 8,432 |
| | 17,414 |
| | 13,970 |
|
| Actuarial loss | | 279,781 |
| | 294,646 |
| | 81,600 |
| | 35,131 |
| | 58,556 |
| | 55,410 |
| |
| Actuarial (gain)/loss | | | (87,617 | ) | | (101,361 | ) | | (25,492 | ) | | (12,289 | ) | | (36,862 | ) | | (23,720 | ) |
| Benefits paid | | (66,330 | ) | | (62,013 | ) | | (18,622 | ) | | (7,113 | ) | | (19,026 | ) | | (11,233 | ) | | (86,121 | ) | | (104,325 | ) | | (24,009 | ) | | (11,029 | ) | | (22,005 | ) | | (20,847 | ) |
| Balance at end of year | |
| $1,485,718 |
| |
| $1,666,535 |
| |
| $432,169 |
| |
| $202,555 |
| |
| $418,498 |
| |
| $334,312 |
| |
| Balance at December 31 | | |
| $1,400,511 |
| |
| $1,564,710 |
| |
| $408,604 |
| |
| $191,064 |
| |
| $383,627 |
| |
| $311,542 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $896,295 |
| |
| $1,031,187 |
| |
| $281,837 |
| |
| $122,960 |
| |
| $295,751 |
| |
| $196,328 |
| |
| Fair value of assets at January 1 | | |
| $977,521 |
| |
| $1,113,359 |
| |
| $301,250 |
| |
| $133,344 |
| |
| $310,713 |
| |
| $217,621 |
|
| Actual return on plan assets | | 52,092 |
| | 59,460 |
| | 16,196 |
| | 6,988 |
| | 16,916 |
| | 11,265 |
| | (24,201 | ) | | (27,175 | ) | | (7,401 | ) | | (3,243 | ) | | (7,487 | ) | | (5,550 | ) |
| Employer contributions | | 95,464 |
| | 84,725 |
| | 21,839 |
| | 10,509 |
| | 17,072 |
| | 21,261 |
| | 92,419 |
| | 89,375 |
| | 22,457 |
| | 10,903 |
| | 17,157 |
| | 20,782 |
|
| Benefits paid | | (66,330 | ) | | (62,013 | ) | | (18,622 | ) | | (7,113 | ) | | (19,026 | ) | | (11,233 | ) | | (86,121 | ) | | (104,325 | ) | | (24,009 | ) | | (11,029 | ) | | (22,005 | ) | | (20,847 | ) |
| Fair value of assets at end of year | |
| $977,521 |
| |
| $1,113,359 |
| |
| $301,250 |
| |
| $133,344 |
| |
| $310,713 |
| |
| $217,621 |
| |
| Fair value of assets at December 31 | | |
| $959,618 |
| |
| $1,071,234 |
| |
| $292,297 |
| |
| $129,975 |
| |
| $298,378 |
| |
| $212,006 |
|
| Funded status | |
| ($508,197 | ) | |
| ($553,176 | ) | |
| ($130,919 | ) | |
| ($69,211 | ) | |
| ($107,785 | ) | |
| ($116,691 | ) | |
| ($440,893 | ) | |
| ($493,476 | ) | |
| ($116,307 | ) | |
| ($61,089 | ) | |
| ($85,249 | ) | |
| ($99,536 | ) |
| Amounts recognized in the balance sheet (funded status) | | | | | | | | | | | | | | | | | | | | | | | | |
| Non-current liabilities | |
| ($508,197 | ) | |
| ($553,176 | ) | |
| ($130,919 | ) | |
| ($69,211 | ) | |
| ($107,785 | ) | |
| ($116,691 | ) | |
| ($440,893 | ) | |
| ($493,476 | ) | |
| ($116,307 | ) | |
| ($61,089 | ) | |
| ($85,249 | ) | |
| ($99,536 | ) |
| Amounts recognized as regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | |
| Net loss | |
| $722,119 |
| |
| $741,474 |
| |
| $198,972 |
| |
| $102,141 |
| |
| $176,522 |
| |
| $172,463 |
| |
| $684,552 |
| |
| $687,305 |
| |
| $190,406 |
| |
| $95,941 |
| |
| $159,085 |
| |
| $159,508 |
|
| Amounts recognized as AOCI (before tax) | | |
| | | | | | | | | | | | |
| | | | | | | | | | |
| Net loss | |
| $— |
| |
| $40,748 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $51,733 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy’s qualified pension plans was $6.7 billion and $6.3 billion at December 31, 2016 and 2015, respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2016 and 2015 was as follows:
|
| | | | | | | |
| | December 31, |
| | 2016 | | 2015 |
| | (In Thousands) |
| Entergy Arkansas |
| $1,379,265 |
| |
| $1,309,903 |
|
| Entergy Louisiana |
| $1,513,884 |
| |
| $1,436,535 |
|
| Entergy Mississippi |
| $396,081 |
| |
| $379,775 |
|
| Entergy New Orleans |
| $186,247 |
| |
| $176,692 |
|
| Entergy Texas |
| $365,251 |
| |
| $359,687 |
|
| System Energy |
| $315,131 |
| |
| $286,917 |
|
Other Postretirement Benefits
Entergy also currently offers retiree medical, dental, vision, and life insurance benefits (other postretirement benefits) for eligible retired employees. Employees who commenced employment before July 1, 2014 and who satisfy certain eligibility requirements (including retiring from Entergy after a certain age and/or years of service with Entergy and immediately commencing their Entergy pension benefit), may become eligible for other postretirement benefits.
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. Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, and Entergy Texas have received regulatory approval to recover accrued other postretirement benefit costs through rates. The LPSC ordered 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’ 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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 master trusts, established by Entergy Corporation and maintained by a trustee. Each participating Registrant Subsidiary holds a beneficial interest in the trusts’ assets. The assets in the master trusts are commingled for investment and administrative purposes. Although assets are commingled, supporting records are maintained for the purpose of allocating the beneficial interest in net 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 income/(loss) is comprised of interest and dividends, realized and unrealized gains and losses, and expenses. Beneficial interest from these investments is allocated to the plans and participating Registrant Subsidiary based on their 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’s and its subsidiaries’ total 2016, 2015, 2014, and 20132014 other postretirement benefit costs, including amounts capitalized and amounts recognized as a regulatory asset and/or other comprehensive income, included the following components:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | |
| Service cost - benefits earned during the period |
| $45,305 |
| |
| $43,493 |
| |
| $74,654 |
|
| $32,291 |
| |
| $45,305 |
| |
| $43,493 |
|
| Interest cost on APBO | 71,934 |
| | 71,841 |
| | 79,453 |
| 56,331 |
| | 71,934 |
| | 71,841 |
|
| Expected return on assets | (45,375 | ) | | (44,787 | ) | | (40,323 | ) | (41,820 | ) | | (45,375 | ) | | (44,787 | ) |
| Amortization of prior service credit | (37,280 | ) | | (31,590 | ) | | (14,904 | ) | (45,490 | ) | | (37,280 | ) | | (31,590 | ) |
| Recognized net loss | 31,573 |
| | 11,143 |
| | 44,178 |
| 18,214 |
| | 31,573 |
| | 11,143 |
|
| Curtailment loss | — |
| | — |
| | 12,729 |
| |
| Net other postretirement benefit cost |
| $66,157 |
| |
| $50,100 |
| |
| $155,787 |
|
| $19,526 |
| |
| $66,157 |
| |
| $50,100 |
|
| 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 |
| ($48,192 | ) | |
| ($35,864 | ) | |
| ($116,571 | ) |
| ($20,353 | ) | |
| ($48,192 | ) | |
| ($35,864 | ) |
| Net loss/(gain) | (154,339 | ) | | 287,313 |
| | (405,976 | ) | 49,805 |
| | (154,339 | ) | | 287,313 |
|
| Amounts reclassified from regulatory asset and /or AOCI to net periodic benefit cost in the current year: | | | | | | | | | | |
| Amortization of prior service credit | 37,280 |
| | 31,590 |
| | 14,904 |
| 45,490 |
| | 37,280 |
| | 31,590 |
|
| Acceleration of prior service credit due to curtailment | — |
| | — |
| | 1,989 |
| |
| Amortization of net loss | (31,573 | ) | | (11,143 | ) | | (44,178 | ) | (18,214 | ) | | (31,573 | ) | | (11,143 | ) |
| Total |
| ($196,824 | ) | |
| $271,896 |
| |
| ($549,832 | ) |
| $56,728 |
| |
| ($196,824 | ) | |
| $271,896 |
|
| Total recognized as net periodic benefit income/(cost), regulatory asset, and/or AOCI (before tax) |
| ($130,667 | ) | |
| $321,996 |
| |
| ($394,045 | ) |
| $76,254 |
| |
| ($130,667 | ) | |
| $321,996 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic benefit cost in the following year | | | | | | | | | | |
| Prior service credit |
| ($45,485 | ) | |
| ($37,280 | ) | |
| ($31,589 | ) |
| ($41,425 | ) | |
| ($45,485 | ) | |
| ($37,280 | ) |
| Net loss |
| $18,214 |
| |
| $31,591 |
| |
| $11,197 |
|
| $21,905 |
| |
| $18,214 |
| |
| $31,591 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Total 2016, 2015, 2014, and 20132014 other postretirement benefit costs of the Registrant Subsidiaries, including amounts capitalized and deferred, for their employees included the following components:
| | | 2015 | |
Entergy
Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | | | |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $6,957 |
| |
| $9,893 |
| |
| $2,028 |
| |
| $818 |
| |
| $2,000 |
| |
| $1,881 |
| |
| $3,913 |
| |
| $7,476 |
| |
| $1,543 |
| |
| $622 |
| |
| $1,590 |
| |
| $1,337 |
|
| Interest cost on APBO | | 12,518 |
| | 16,311 |
| | 3,436 |
| | 2,608 |
| | 5,366 |
| | 2,511 |
| | 9,297 |
| | 13,041 |
| | 2,835 |
| | 1,791 |
| | 4,154 |
| | 2,117 |
|
| Expected return on assets | | (19,190 | ) | | — |
| | (6,166 | ) | | (4,804 | ) | | (10,351 | ) | | (3,644 | ) | | (17,855 | ) | | — |
| | (5,517 | ) | | (4,617 | ) | | (9,575 | ) | | (3,257 | ) |
| Amortization of prior credit | | (2,441 | ) | | (7,467 | ) | | (916 | ) | | (709 | ) | | (2,723 | ) | | (1,465 | ) | | (5,472 | ) | | (7,787 | ) | | (934 | ) | | (745 | ) | | (2,722 | ) | | (1,570 | ) |
| Recognized net loss | | 5,356 |
| | 7,118 |
| | 860 |
| | 470 |
| | 2,740 |
| | 1,198 |
| | 4,256 |
| | 2,926 |
| | 893 |
| | 146 |
| | 2,148 |
| | 1,149 |
|
| Net other postretirement benefit (income)/cost | |
| $3,200 |
| |
| $25,855 |
| |
| ($758 | ) | |
| ($1,617 | ) | |
| ($2,968 | ) | |
| $481 |
| |
| ($5,861 | ) | |
| $15,656 |
| |
| ($1,180 | ) | |
| ($2,803 | ) | |
| ($4,405 | ) | |
| ($224 | ) |
| 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 the period | |
| ($18,035 | ) | |
| ($1,361 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($644 | ) | |
| ($1,007 | ) | |
| ($4,647 | ) | |
| ($6,219 | ) | |
| $— |
| |
| $— |
| |
| $— |
|
| Net (gain)/loss | | (11,978 | ) | | (47,043 | ) | | 774 |
| | (5,810 | ) | | (4,907 | ) | | 305 |
| | 3,331 |
| | (13,117 | ) | | 8,715 |
| | 5,717 |
| | 13,378 |
| | 4,997 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | |
| | | | | | | | | | | |
| | | | | | | | | | |
| Amortization of prior service credit | | 2,441 |
| | 7,467 |
| | 916 |
| | 709 |
| | 2,723 |
| | 1,465 |
| | 5,472 |
| | 7,787 |
| | 934 |
| | 745 |
| | 2,722 |
| | 1,570 |
|
| Amortization of net loss | | (5,356 | ) | | (7,118 | ) | | (860 | ) | | (470 | ) | | (2,740 | ) | | (1,198 | ) | | (4,256 | ) | | (2,926 | ) | | (893 | ) | | (146 | ) | | (2,148 | ) | | (1,149 | ) |
| Total | |
| ($32,928 | ) | |
| ($48,055 | ) | |
| $830 |
| |
| ($5,571 | ) | |
| ($4,924 | ) | |
| ($72 | ) | |
| $3,540 |
| |
| ($12,903 | ) | |
| $2,537 |
| |
| $6,316 |
| |
| $13,952 |
| |
| $5,418 |
|
| Total recognized as net periodic other postretirement income/(cost), regulatory asset, and/or AOCI (before tax) | |
| ($29,728 | ) | |
| ($22,200 | ) | |
| $72 |
| |
| ($7,188 | ) | |
| ($7,892 | ) | |
| $409 |
| |
| ($2,321 | ) | |
| $2,753 |
| |
| $1,357 |
| |
| $3,513 |
| |
| $9,547 |
| |
| $5,194 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($5,472 | ) | |
| ($7,783 | ) | |
| ($933 | ) | |
| ($745 | ) | |
| ($2,722 | ) | |
| ($1,570 | ) | |
| ($5,110 | ) | |
| ($7,739 | ) | |
| ($1,824 | ) | |
| ($745 | ) | |
| ($2,316 | ) | |
| ($1,513 | ) |
| Net loss | |
| $4,256 |
| |
| $2,926 |
| |
| $893 |
| |
| $146 |
| |
| $2,148 |
| |
| $1,149 |
| |
| $4,460 |
| |
| $1,859 |
| |
| $1,675 |
| |
| $418 |
| |
| $3,303 |
| |
| $1,560 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas |
| Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas |
| Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $5,957 |
| |
| $9,414 |
| |
| $1,900 |
| |
| $868 |
| |
| $2,378 |
| |
| $2,058 |
| |
| $6,957 |
| |
| $9,893 |
| |
| $2,028 |
| |
| $818 |
| |
| $2,000 |
| |
| $1,881 |
|
| Interest cost on APBO | | 12,261 |
| | 16,642 |
| | 3,655 |
| | 2,805 |
| | 5,652 |
| | 2,611 |
| | 12,518 |
| | 16,311 |
| | 3,436 |
| | 2,608 |
| | 5,366 |
| | 2,511 |
|
| Expected return on assets | | (19,135 | ) | | — |
| | (5,771 | ) | | (4,475 | ) | | (10,358 | ) | | (3,727 | ) | | (19,190 | ) | | — |
| | (6,166 | ) | | (4,804 | ) | | (10,351 | ) | | (3,644 | ) |
| Amortization of prior credit | | (2,441 | ) | | (5,614 | ) | | (915 | ) | | (709 | ) | | (1,300 | ) | | (824 | ) | | (2,441 | ) | | (7,467 | ) | | (916 | ) | | (709 | ) | | (2,723 | ) | | (1,465 | ) |
| Recognized net loss | | 1,267 |
| | 2,723 |
| | 149 |
| | 56 |
| | 801 |
| | 443 |
| | 5,356 |
| | 7,118 |
| | 860 |
| | 470 |
| | 2,740 |
| | 1,198 |
|
| Net other postretirement benefit (income)/cost | |
| ($2,091 | ) | |
| $23,165 |
| |
| ($982 | ) | |
| ($1,455 | ) | |
| ($2,827 | ) | |
| $561 |
| |
| $3,200 |
| |
| $25,855 |
| |
| ($758 | ) | |
| ($1,617 | ) | |
| ($2,968 | ) | |
| $481 |
|
| 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 the period | |
| $— |
| |
| ($12,845 | ) | |
| $— |
| |
| $— |
| |
| ($8,536 | ) | |
| ($3,845 | ) | |
| ($18,035 | ) | |
| ($1,361 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($644 | ) |
| Net loss | | 55,642 |
| | 61,049 |
| | 9,525 |
| | 6,309 |
| | 24,482 |
| | 10,596 |
| |
| Net (gain)/loss | | | (11,978 | ) | | (47,043 | ) | | 774 |
| | (5,810 | ) | | (4,907 | ) | | 305 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service credit | | 2,441 |
| | 5,614 |
| | 915 |
| | 709 |
| | 1,300 |
| | 824 |
| | 2,441 |
| | 7,467 |
| | 916 |
| | 709 |
| | 2,723 |
| | 1,465 |
|
| Amortization of net loss | | (1,267 | ) | | (2,723 | ) | | (149 | ) | | (56 | ) | | (801 | ) | | (443 | ) | | (5,356 | ) | | (7,118 | ) | | (860 | ) | | (470 | ) | | (2,740 | ) | | (1,198 | ) |
| Total | |
| $56,816 |
| |
| $51,095 |
| |
| $10,291 |
| |
| $6,962 |
| |
| $16,445 |
| |
| $7,132 |
| |
| ($32,928 | ) | |
| ($48,055 | ) | |
| $830 |
| |
| ($5,571 | ) | |
| ($4,924 | ) | |
| ($72 | ) |
| Total recognized as net periodic other postretirement income, regulatory asset, and/or AOCI (before tax) | |
| $54,725 |
| |
| $74,260 |
| |
| $9,309 |
| |
| $5,507 |
| |
| $13,618 |
| |
| $7,693 |
| |
| ($29,728 | ) | |
| ($22,200 | ) | |
| $72 |
| |
| ($7,188 | ) | |
| ($7,892 | ) | |
| $409 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($2,441 | ) | |
| ($7,467 | ) | |
| ($916 | ) | |
| ($709 | ) | |
| ($2,723 | ) | |
| ($1,465 | ) | |
| ($5,472 | ) | |
| ($7,783 | ) | |
| ($933 | ) | |
| ($745 | ) | |
| ($2,722 | ) | |
| ($1,570 | ) |
| Net loss | |
| $5,356 |
| |
| $7,118 |
| |
| $860 |
| |
| $470 |
| |
| $2,740 |
| |
| $1,198 |
| |
| $4,256 |
| |
| $2,926 |
| |
| $893 |
| |
| $146 |
| |
| $2,148 |
| |
| $1,149 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2014 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Other postretirement costs: | | | | | | | | | | | | | | | | | | | | | | | | |
| Service cost - benefits earned during the period | |
| $9,619 |
| |
| $16,451 |
| |
| $3,246 |
| |
| $1,752 |
| |
| $3,760 |
| |
| $3,580 |
| |
| $5,957 |
| |
| $9,414 |
| |
| $1,900 |
| |
| $868 |
| |
| $2,378 |
| |
| $2,058 |
|
| Interest cost on APBO | | 13,545 |
| | 18,374 |
| | 4,289 |
| | 3,135 |
| | 6,076 |
| | 2,945 |
| | 12,261 |
| | 16,642 |
| | 3,655 |
| | 2,805 |
| | 5,652 |
| | 2,611 |
|
| Expected return on assets | | (16,843 | ) | | — |
| | (5,335 | ) | | (4,101 | ) | | (9,391 | ) | | (3,350 | ) | | (19,135 | ) | | — |
| | (5,771 | ) | | (4,475 | ) | | (10,358 | ) | | (3,727 | ) |
| Amortization of prior service credit | | (689 | ) | | (1,450 | ) | | (204 | ) | | (24 | ) | | (501 | ) | | (126 | ) | | (2,441 | ) | | (5,614 | ) | | (915 | ) | | (709 | ) | | (1,300 | ) | | (824 | ) |
| Recognized net loss | | 7,976 |
| | 9,648 |
| | 2,534 |
| | 1,509 |
| | 3,744 |
| | 1,896 |
| | 1,267 |
| | 2,723 |
| | 149 |
| | 56 |
| | 801 |
| | 443 |
|
| Curtailment loss | | 4,517 |
| | 3,394 |
| | 596 |
| | 354 |
| | 1,436 |
| | 760 |
| |
| Net other postretirement benefit cost | |
| $18,125 |
| |
| $46,417 |
| |
| $5,126 |
| |
| $2,625 |
| |
| $5,124 |
| |
| $5,705 |
| |
| ($2,091 | ) | |
| $23,165 |
| |
| ($982 | ) | |
| ($1,455 | ) | |
| ($2,827 | ) | |
| $561 |
|
| 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 the period | |
| ($11,617 | ) | |
| ($27,549 | ) | |
| ($4,714 | ) | |
| ($4,469 | ) | |
| ($5,359 | ) | |
| ($4,591 | ) | |
| $— |
| |
| ($12,845 | ) | |
| $— |
| |
| $— |
| |
| ($8,536 | ) | |
| ($3,845 | ) |
| Net loss | | (81,236 | ) | | (84,681 | ) | | (30,018 | ) | | (18,508 | ) | | (34,562 | ) | | (17,579 | ) | | 55,642 |
| | 61,049 |
| | 9,525 |
| | 6,309 |
| | 24,482 |
| | 10,596 |
|
| Amounts reclassified from regulatory asset and/or AOCI to net periodic pension cost in the current year: | | | | | | | | | | | | | | | | | | | | | | | | |
| Amortization of prior service credit | | 689 |
| | 1,450 |
| | 204 |
| | 24 |
| | 501 |
| | 126 |
| | 2,441 |
| | 5,614 |
| | 915 |
| | 709 |
| | 1,300 |
| | 824 |
|
| Acceleration of prior service credit/(cost) due to curtailment | | 78 |
| | 132 |
| | 20 |
| | (4 | ) | | 62 |
| | 9 |
| |
| Amortization of net loss | | (7,976 | ) | | (9,648 | ) | | (2,534 | ) | | (1,509 | ) | | (3,744 | ) | | (1,896 | ) | | (1,267 | ) | | (2,723 | ) | | (149 | ) | | (56 | ) | | (801 | ) | | (443 | ) |
| Total | |
| ($100,062 | ) | |
| ($120,296 | ) | |
| ($37,042 | ) | |
| ($24,466 | ) | |
| ($43,102 | ) | |
| ($23,931 | ) | |
| $56,816 |
| |
| $51,095 |
| |
| $10,291 |
| |
| $6,962 |
| |
| $16,445 |
| |
| $7,132 |
|
| Total recognized as net periodic other postretirement cost, regulatory asset, and/or AOCI (before tax) | |
| ($81,937 | ) | |
| ($73,879 | ) | |
| ($31,916 | ) | |
| ($21,841 | ) | |
| ($37,978 | ) | |
| ($18,226 | ) | |
| $54,725 |
| |
| $74,260 |
| |
| $9,309 |
| |
| $5,507 |
| |
| $13,618 |
| |
| $7,693 |
|
| Estimated amortization amounts from regulatory asset and/or AOCI to net periodic cost in the following year | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($2,441 | ) | |
| ($5,612 | ) | |
| ($918 | ) | |
| ($709 | ) | |
| ($1,301 | ) | |
| ($824 | ) | |
| ($2,441 | ) | |
| ($7,467 | ) | |
| ($916 | ) | |
| ($709 | ) | |
| ($2,723 | ) | |
| ($1,465 | ) |
| Net loss | |
| $1,267 |
| |
| $2,723 |
| |
| $149 |
| |
| $56 |
| |
| $800 |
| |
| $464 |
| |
| $5,356 |
| |
| $7,118 |
| |
| $860 |
| |
| $470 |
| |
| $2,740 |
| |
| $1,198 |
|
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
Other postretirement benefit obligations, plan assets, funded status, and amounts not yet recognized and recognized in the Consolidated Balance Sheets of Entergy Corporation and its Subsidiaries as of December 31, 2016 and 2015 and 2014are as follows:
| | | | December 31, | | | | | |
| | 2015 | | 2014 | 2016 | | 2015 |
| | (In Thousands) | (In Thousands) |
| Change in APBO | |
| | |
| |
| | |
|
| Balance at beginning of year |
| $1,739,557 |
| |
| $1,461,910 |
| |
| Balance at January 1 | |
| $1,530,829 |
| |
| $1,739,557 |
|
| Service cost | 45,305 |
| | 43,493 |
| 32,291 |
| | 45,305 |
|
| Interest cost | 71,934 |
| | 71,841 |
| 56,331 |
| | 71,934 |
|
| Plan amendments | (48,192 | ) | | (35,864 | ) | (20,353 | ) | | (48,192 | ) |
| Plan participant contributions | 29,685 |
| | 22,160 |
| 27,686 |
| | 29,685 |
|
| Actuarial (gain)/loss | (208,017 | ) | | 274,061 |
| 46,201 |
| | (208,017 | ) |
| Benefits paid | (102,618 | ) | | (102,439 | ) | (104,477 | ) | | (102,618 | ) |
| Medicare Part D subsidy received | 3,175 |
| | 4,395 |
| 455 |
| | 3,175 |
|
| Balance at end of year |
| $1,530,829 |
| |
| $1,739,557 |
| |
| Balance at December 31 | |
| $1,568,963 |
| |
| $1,530,829 |
|
| Change in Plan Assets | |
| | |
| |
| | |
|
| Fair value of assets at beginning of year |
| $597,627 |
| |
| $569,850 |
| |
| Fair value of assets at January 1 | |
| $579,069 |
| |
| $597,627 |
|
| Actual return on plan assets | (8,303 | ) | | 31,535 |
| 38,216 |
| | (8,303 | ) |
| Employer contributions | 62,678 |
| | 76,521 |
| 56,166 |
| | 62,678 |
|
| Plan participant contributions | 29,685 |
| | 22,160 |
| 27,686 |
| | 29,685 |
|
| Benefits paid | (102,618 | ) | | (102,439 | ) | (104,477 | ) | | (102,618 | ) |
| Fair value of assets at end of year |
| $579,069 |
| |
| $597,627 |
| |
| Fair value of assets at December 31 | |
| $596,660 |
| |
| $579,069 |
|
| Funded status |
| ($951,760 | ) | |
| ($1,141,930 | ) |
| ($972,303 | ) | |
| ($951,760 | ) |
| Amounts recognized in the balance sheet | | | | | | |
| Current liabilities |
| ($41,326 | ) | |
| ($41,821 | ) |
| ($45,255 | ) | |
| ($41,326 | ) |
| Non-current liabilities | (910,434 | ) | | (1,100,109 | ) | (927,048 | ) | | (910,434 | ) |
| Total funded status |
| ($951,760 | ) | |
| ($1,141,930 | ) |
| ($972,303 | ) | |
| ($951,760 | ) |
| Amounts recognized as a regulatory asset | | | | | | |
| Prior service credit |
| ($61,833 | ) | |
| ($54,508 | ) |
| ($54,896 | ) | |
| ($61,833 | ) |
| Net loss | 191,782 |
| | 248,918 |
| 222,540 |
| | 191,782 |
|
| |
| $129,949 |
| |
| $194,410 |
|
| $167,644 |
| |
| $129,949 |
|
| Amounts recognized as AOCI (before tax) | | | | | | |
| Prior service credit |
| ($107,673 | ) | |
| ($104,086 | ) |
| ($89,474 | ) | |
| ($107,673 | ) |
| Net loss | 171,742 |
| | 300,518 |
| 172,575 |
| | 171,742 |
|
| |
| $64,069 |
| |
| $196,432 |
|
| $83,101 |
| |
| $64,069 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Other Postretirement Benefit Obligations, Plan Assets, Funded Status,postretirement benefit obligations, plan assets, funded status, and Amounts Not Yet Recognizedamounts not yet recognized and Recognizedrecognized in the Balance Sheets of the Registrant Subsidiaries as of December 31, 2016 and 2015 and 2014are as follows:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $303,716 |
| |
| $394,946 |
| |
| $83,162 |
| |
| $63,779 |
| |
| $130,145 |
| |
| $60,754 |
| |
| Balance at January 1 | | |
| $258,900 |
| |
| $356,253 |
| |
| $77,382 |
| |
| $51,951 |
| |
| $114,582 |
| |
| $57,645 |
|
| Service cost | | 6,957 |
| | 9,893 |
| | 2,028 |
| | 818 |
| | 2,000 |
| | 1,881 |
| | 3,913 |
| | 7,476 |
| | 1,543 |
| | 622 |
| | 1,590 |
| | 1,337 |
|
| Interest cost | | 12,518 |
| | 16,311 |
| | 3,436 |
| | 2,608 |
| | 5,366 |
| | 2,511 |
| | 9,297 |
| | 13,041 |
| | 2,835 |
| | 1,791 |
| | 4,154 |
| | 2,117 |
|
| Plan amendments | | (18,035 | ) | | (1,361 | ) | | — |
| | — |
| | — |
| | (644 | ) | | (1,007 | ) | | (4,647 | ) | | (6,219 | ) | | — |
| | — |
| | — |
|
| Plan participant contributions | | 6,818 |
| | 6,864 |
| | 1,884 |
| | 1,259 |
| | 2,092 |
| | 1,530 |
| | 6,330 |
| | 6,273 |
| | 1,721 |
| | 1,213 |
| | 1,927 |
| | 1,390 |
|
| Actuarial gain | | (34,217 | ) | | (47,043 | ) | | (6,407 | ) | | (12,118 | ) | | (17,052 | ) | | (3,973 | ) | |
| Actuarial (gain)/loss | | | 2,453 |
| | (13,117 | ) | | 8,230 |
| | 4,774 |
| | 12,389 |
| | 4,806 |
|
| Benefits paid | | (19,476 | ) | | (24,182 | ) | | (6,927 | ) | | (4,532 | ) | | (8,275 | ) | | (4,532 | ) | | (21,178 | ) | | (22,893 | ) | | (7,031 | ) | | (4,852 | ) | | (6,977 | ) | | (4,818 | ) |
| Medicare Part D subsidy received | | 619 |
| | 825 |
| | 206 |
| | 137 |
| | 306 |
| | 118 |
| | 79 |
| | 114 |
| | 24 |
| | 16 |
| | 35 |
| | 21 |
|
| Balance at end of year | |
| $258,900 |
| |
| $356,253 |
| |
| $77,382 |
| |
| $51,951 |
| |
| $114,582 |
| |
| $57,645 |
| |
| Balance at December 31 | | |
| $258,787 |
| |
| $342,500 |
| |
| $78,485 |
| |
| $55,515 |
| |
| $127,700 |
| |
| $62,498 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $244,191 |
| |
| $— |
| |
| $80,935 |
| |
| $71,004 |
| |
| $135,733 |
| |
| $48,293 |
| |
| Fair value of assets at January 1 | | |
| $243,206 |
| |
| $— |
| |
| $75,538 |
| |
| $69,881 |
| |
| $130,374 |
| |
| $44,917 |
|
| Actual return on plan assets | | (3,049 | ) | | — |
| | (1,015 | ) | | (1,504 | ) | | (1,794 | ) | | (634 | ) | | 16,977 |
| | — |
| | 5,032 |
| | 3,674 |
| | 8,586 |
| | 3,066 |
|
| Employer contributions | | 14,722 |
| | 17,318 |
| | 661 |
| | 3,654 |
| | 2,618 |
| | 260 |
| | 5,591 |
| | 16,620 |
| | 685 |
| | 4,320 |
| | 3,159 |
| | 330 |
|
| Plan participant contributions | | 6,818 |
| | 6,864 |
| | 1,884 |
| | 1,259 |
| | 2,092 |
| | 1,530 |
| | 6,330 |
| | 6,273 |
| | 1,721 |
| | 1,213 |
| | 1,927 |
| | 1,390 |
|
| Benefits paid | | (19,476 | ) | | (24,182 | ) | | (6,927 | ) | | (4,532 | ) | | (8,275 | ) | | (4,532 | ) | | (21,178 | ) | | (22,893 | ) | | (7,031 | ) | | (4,852 | ) | | (6,977 | ) | | (4,818 | ) |
| Fair value of assets at end of year | |
| $243,206 |
| |
| $— |
| |
| $75,538 |
| |
| $69,881 |
| |
| $130,374 |
| |
| $44,917 |
| |
| Fair value of assets at December 31 | | |
| $250,926 |
| |
| $— |
| |
| $75,945 |
| |
| $74,236 |
| |
| $137,069 |
| |
| $44,885 |
|
| Funded status | |
| ($15,694 | ) | |
| ($356,253 | ) | |
| ($1,844 | ) | |
| $17,930 |
| |
| $15,792 |
| |
| ($12,728 | ) | |
| ($7,861 | ) | |
| ($342,500 | ) | |
| ($2,540 | ) | |
| $18,721 |
| |
| $9,369 |
| |
| ($17,613 | ) |
| Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities | |
| $— |
| |
| ($18,857 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($19,209 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Non-current liabilities | | (15,694 | ) | | (337,396 | ) | | (1,844 | ) | | 17,930 |
| | 15,792 |
| | (12,728 | ) | | (7,861 | ) | | (323,291 | ) | | (2,540 | ) | | 18,721 |
| | 9,369 |
| | (17,613 | ) |
| Total funded status | |
| ($15,694 | ) | |
| ($356,253 | ) | |
| ($1,844 | ) | |
| $17,930 |
| |
| $15,792 |
| |
| ($12,728 | ) | |
| ($7,861 | ) | |
| ($342,500 | ) | |
| ($2,540 | ) | |
| $18,721 |
| |
| $9,369 |
| |
| ($17,613 | ) |
| Amounts recognized in regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($26,149 | ) | |
| $— |
| |
| ($3,225 | ) | |
| ($2,917 | ) | |
| ($11,018 | ) | |
| ($6,902 | ) | |
| ($21,684 | ) | |
| $— |
| |
| ($8,511 | ) | |
| ($2,172 | ) | |
| ($8,296 | ) | |
| ($5,332 | ) |
| Net loss | | 77,313 |
| | — |
| | 18,594 |
| | 6,458 |
| | 38,806 |
| | 19,557 |
| | 76,388 |
| | — |
| | 26,416 |
| | 12,029 |
| | 50,036 |
| | 23,405 |
|
| | |
| $51,164 |
| |
| $— |
| |
| $15,369 |
| |
| $3,541 |
| |
| $27,788 |
| |
| $12,655 |
| |
| $54,704 |
| |
| $— |
| |
| $17,905 |
| |
| $9,857 |
| |
| $41,740 |
| |
| $18,073 |
|
| Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| $— |
| |
| ($30,874 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($27,735 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Net loss | | — |
| | 70,743 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 54,700 |
| | — |
| | — |
| | — |
| | — |
|
| | |
| $— |
| |
| $39,869 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $26,965 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Change in APBO | | | | | | | | | | | | | | | | | | | | | | | | |
| Balance at beginning of year | |
| $250,734 |
| |
| $339,066 |
| |
| $74,539 |
| |
| $57,874 |
| |
| $115,418 |
| |
| $53,051 |
| |
| Balance at January 1 | | |
| $303,716 |
| |
| $394,946 |
| |
| $83,162 |
| |
| $63,779 |
| |
| $130,145 |
| |
| $60,754 |
|
| Service cost | | 5,957 |
| | 9,414 |
| | 1,900 |
| | 868 |
| | 2,378 |
| | 2,058 |
| | 6,957 |
| | 9,893 |
| | 2,028 |
| | 818 |
| | 2,000 |
| | 1,881 |
|
| Interest cost | | 12,261 |
| | 16,642 |
| | 3,655 |
| | 2,805 |
| | 5,652 |
| | 2,611 |
| | 12,518 |
| | 16,311 |
| | 3,436 |
| | 2,608 |
| | 5,366 |
| | 2,511 |
|
| Plan amendments | | — |
| | (12,845 | ) | | — |
| | — |
| | (8,536 | ) | | (3,845 | ) | | (18,035 | ) | | (1,361 | ) | | — |
| | — |
| | — |
| | (644 | ) |
| Plan participant contributions | | 5,195 |
| | 5,071 |
| | 1,396 |
| | 1,044 |
| | 1,655 |
| | 1,061 |
| | 6,818 |
| | 6,864 |
| | 1,884 |
| | 1,259 |
| | 2,092 |
| | 1,530 |
|
| Actuarial loss | | 49,573 |
| | 61,049 |
| | 7,939 |
| | 5,097 |
| | 21,471 |
| | 9,524 |
| |
| Actuarial (gain)/loss | | | (34,217 | ) | | (47,043 | ) | | (6,407 | ) | | (12,118 | ) | | (17,052 | ) | | (3,973 | ) |
| Benefits paid | | (20,984 | ) | | (24,625 | ) | | (6,589 | ) | | (4,131 | ) | | (8,333 | ) | | (3,858 | ) | | (19,476 | ) | | (24,182 | ) | | (6,927 | ) | | (4,532 | ) | | (8,275 | ) | | (4,532 | ) |
| Medicare Part D subsidy received | | 980 |
| | 1,174 |
| | 322 |
| | 222 |
| | 440 |
| | 152 |
| | 619 |
| | 825 |
| | 206 |
| | 137 |
| | 306 |
| | 118 |
|
| Balance at end of year | |
| $303,716 |
| |
| $394,946 |
| |
| $83,162 |
| |
| $63,779 |
| |
| $130,145 |
| |
| $60,754 |
| |
| Balance at December 31 | | |
| $258,900 |
| |
| $356,253 |
| |
| $77,382 |
| |
| $51,951 |
| |
| $114,582 |
| |
| $57,645 |
|
| Change in Plan Assets | | | | | | | | | | | | | | | | | | | | | | | | |
| Fair value of assets at beginning of year | |
| $231,663 |
| |
| $— |
| |
| $73,438 |
| |
| $66,539 |
| |
| $131,618 |
| |
| $48,101 |
| |
| Fair value of assets at January 1 | | |
| $244,191 |
| |
| $— |
| |
| $80,935 |
| |
| $71,004 |
| |
| $135,733 |
| |
| $48,293 |
|
| Actual return on plan assets | | 13,066 |
| | — |
| | 4,185 |
| | 3,263 |
| | 7,347 |
| | 2,655 |
| | (3,049 | ) | | — |
| | (1,015 | ) | | (1,504 | ) | | (1,794 | ) | | (634 | ) |
| Employer contributions | | 15,251 |
| | 19,554 |
| | 8,505 |
| | 4,289 |
| | 3,446 |
| | 334 |
| | 14,722 |
| | 17,318 |
| | 661 |
| | 3,654 |
| | 2,618 |
| | 260 |
|
| Plan participant contributions | | 5,195 |
| | 5,071 |
| | 1,396 |
| | 1,044 |
| | 1,655 |
| | 1,061 |
| | 6,818 |
| | 6,864 |
| | 1,884 |
| | 1,259 |
| | 2,092 |
| | 1,530 |
|
| Benefits paid | | (20,984 | ) | | (24,625 | ) | | (6,589 | ) | | (4,131 | ) | | (8,333 | ) | | (3,858 | ) | | (19,476 | ) | | (24,182 | ) | | (6,927 | ) | | (4,532 | ) | | (8,275 | ) | | (4,532 | ) |
| Fair value of assets at end of year | |
| $244,191 |
| |
| $— |
| |
| $80,935 |
| |
| $71,004 |
| |
| $135,733 |
| |
| $48,293 |
| |
| Fair value of assets at December 31 | | |
| $243,206 |
| |
| $— |
| |
| $75,538 |
| |
| $69,881 |
| |
| $130,374 |
| |
| $44,917 |
|
| Funded status | |
| ($59,525 | ) | |
| ($394,946 | ) | |
| ($2,227 | ) | |
| $7,225 |
| |
| $5,588 |
| |
| ($12,461 | ) | |
| ($15,694 | ) | |
| ($356,253 | ) | |
| ($1,844 | ) | |
| $17,930 |
| |
| $15,792 |
| |
| ($12,728 | ) |
| Amounts recognized in the balance sheet | | | | | | | | | | | | | | | | | | | | | | | | |
| Current liabilities | |
| $— |
| |
| ($18,724 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($18,857 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Non-current liabilities | | (59,525 | ) | | (376,222 | ) | | (2,227 | ) | | 7,225 |
| | 5,558 |
| | (12,461 | ) | | (15,694 | ) | | (337,396 | ) | | (1,844 | ) | | 17,930 |
| | 15,792 |
| | (12,728 | ) |
| Total funded status | |
| ($59,525 | ) | |
| ($394,946 | ) | |
| ($2,227 | ) | |
| $7,225 |
| |
| $5,558 |
| |
| ($12,461 | ) | |
| ($15,694 | ) | |
| ($356,253 | ) | |
| ($1,844 | ) | |
| $17,930 |
| |
| $15,792 |
| |
| ($12,728 | ) |
| Amounts recognized in regulatory asset | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| ($10,555 | ) | |
| $— |
| |
| ($4,141 | ) | |
| ($3,626 | ) | |
| ($13,741 | ) | |
| ($7,723 | ) | |
| ($26,149 | ) | |
| $— |
| |
| ($3,225 | ) | |
| ($2,917 | ) | |
| ($11,018 | ) | |
| ($6,902 | ) |
| Net loss | | 94,647 |
| | — |
| | 18,680 |
| | 12,738 |
| | 46,453 |
| | 20,450 |
| | 77,313 |
| | — |
| | 18,594 |
| | 6,458 |
| | 38,806 |
| | 19,557 |
|
| | |
| $84,092 |
| |
| $— |
| |
| $14,539 |
| |
| $9,112 |
| |
| $32,712 |
| |
| $12,727 |
| |
| $51,164 |
| |
| $— |
| |
| $15,369 |
| |
| $3,541 |
| |
| $27,788 |
| |
| $12,655 |
|
| Amounts recognized in AOCI (before tax) | | | | | | | | | | | | | | | | | | | | | | | | |
| Prior service credit | |
| $— |
| |
| ($36,980 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| ($30,874 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
| Net loss | | — |
| | 124,904 |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 70,743 |
| | — |
| | — |
| | — |
| | — |
|
| | |
| $— |
| |
| $87,924 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $39,869 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 $24.9 million in 2016, $22.8 million in 2015, and $32.4 million in 2014,2014. In 2016, 2015, and $54.5 million in 2013. In 2015, 2014 and 2013 Entergy recognized $8.1 million, $5.1 million, $15.1 million, and $33$15.1 million, respectively in settlement charges 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 $157.3$169.3 million and $151.8$157.3 million as of December 31, 20152016 and 2014,2015, respectively. The accumulated benefit obligation was $137.6$151 million and $130.6$137.6 million as of December 31, 20152016 and 2014,2015, respectively.
Entergy’s non-qualified, non-current pension liability at December 31, 2016 and 2015 and 2014 was $136.1$137.6 million and $135.6$136.1 million, respectively; and its current liability was $21.2$31.7 million and $16.2$21.2 million, respectively. The unamortized prior service cost and net loss are recognized in regulatory assets ($58.859.8 million at December 31, 20152016 and $60.3$58.8 million at December 31, 2014)2015) and accumulated other comprehensive income before taxes ($23.531.6 million at December 31, 20152016 and $23.5 million at December 31, 2014)2015).
The following 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 their employees for the non-qualified plans for 2016, 2015, 2014, and 2013,2014, was as follows:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) | (In Thousands) |
| 2016 | |
| $1,819 |
| |
| $231 |
| |
| $236 |
| |
| $65 |
| |
| $504 |
|
| 2015 |
| $446 |
| |
| $377 |
| |
| $235 |
| |
| $64 |
| |
| $595 |
|
| $446 |
| |
| $377 |
| |
| $235 |
| |
| $64 |
| |
| $595 |
|
| 2014 |
| $754 |
| |
| $135 |
| |
| $190 |
| |
| $95 |
| |
| $491 |
|
| $754 |
| |
| $135 |
| |
| $190 |
| |
| $95 |
| |
| $491 |
|
| 2013 |
| $448 |
| |
| $163 |
| |
| $192 |
| |
| $92 |
| |
| $1,001 |
| |
Included in the 2016 net periodic pension cost above are settlement charges of $1.4 million and $1 thousand for Entergy Arkansas and Entergy Mississippi, respectively, related to the lump sum benefits paid out of the plan. Included in the 2015 net periodic pension cost above are settlement charges of $108 thousand and $2 thousand for Entergy Louisiana and Entergy Mississippi, respectively, related to the lump sum benefits paid out of the plan. Included in the 2014 net periodic pension cost above are settlement charges of $337 thousand and $16 thousand for Entergy Arkansas and Entergy Texas, respectively, related to the lump sum benefits paid out of the plan. Included in the 2013 net periodic pension cost above are settlement charges of $415 thousand for Entergy Texas related to the lump sum benefits paid out of the plan.
The projected benefit obligation for their employees for the non-qualified plans as of December 31, 20152016 and 20142015 was as follows:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) | (In Thousands) |
| 2016 | |
| $3,897 |
| |
| $2,134 |
| |
| $2,296 |
| |
| $514 |
| |
| $8,665 |
|
| 2015 |
| $4,694 |
| |
| $2,550 |
| |
| $2,185 |
| |
| $468 |
| |
| $8,832 |
|
| $4,694 |
| |
| $2,550 |
| |
| $2,185 |
| |
| $468 |
| |
| $8,832 |
|
| 2014 |
| $4,495 |
| |
| $2,851 |
| |
| $2,128 |
| |
| $476 |
| |
| $9,567 |
| |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The accumulated benefit obligation for their employees for the non-qualified plans as of December 31, 20152016 and 20142015 was as follows:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Thousands) | (In Thousands) |
| 2016 | |
| $3,439 |
| |
| $2,134 |
| |
| $1,961 |
| |
| $452 |
| |
| $8,333 |
|
| 2015 |
| $4,495 |
| |
| $2,538 |
| |
| $1,802 |
| |
| $417 |
| |
| $8,460 |
|
| $4,495 |
| |
| $2,538 |
| |
| $1,802 |
| |
| $417 |
| |
| $8,460 |
|
| 2014 |
| $4,086 |
| |
| $2,824 |
| |
| $1,761 |
| |
| $436 |
| |
| $9,215 |
| |
The following amounts were recorded on the balance sheet as of December 31, 20152016 and 2014:2015:
| | | 2015 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | |
| 2016 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| Current liabilities | |
| ($2,128 | ) | |
| ($237 | ) | |
| ($119 | ) | |
| ($19 | ) | |
| ($773 | ) | |
| ($242 | ) | |
| ($233 | ) | |
| ($137 | ) | |
| ($20 | ) | |
| ($773 | ) |
| Non-current liabilities | | (2,566 | ) | | (2,313 | ) | | (2,066 | ) | | (449 | ) | | (8,059 | ) | | (3,655 | ) | | (1,901 | ) | | (2,159 | ) | | (495 | ) | | (7,892 | ) |
| Total funded status | |
| ($4,694 | ) | |
| ($2,550 | ) | |
| ($2,185 | ) | |
| ($468 | ) | |
| ($8,832 | ) | |
| ($3,897 | ) | |
| ($2,134 | ) | |
| ($2,296 | ) | |
| ($515 | ) | |
| ($8,665 | ) |
| Regulatory asset/(liability) | |
| $2,356 |
| |
| $544 |
| |
| $883 |
| |
| ($136 | ) | |
| ($333 | ) | |
| $2,914 |
| |
| $175 |
| |
| $876 |
| |
| ($148 | ) | |
| ($316 | ) |
| Accumulated other comprehensive income (before taxes) | |
| $— |
| |
| $41 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $13 |
| |
| $— |
| |
| $— |
| |
| $— |
|
| | | 2014 | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | |
| 2015 | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| Current liabilities | |
| ($347 | ) | |
| ($259 | ) | |
| ($119 | ) | |
| ($23 | ) | |
| ($753 | ) | |
| ($2,128 | ) | |
| ($237 | ) | |
| ($119 | ) | |
| ($19 | ) | |
| ($773 | ) |
| Non-current liabilities | | (4,148 | ) | | (2,592 | ) | | (2,009 | ) | | (453 | ) | | (8,814 | ) | | (2,566 | ) | | (2,313 | ) | | (2,066 | ) | | (449 | ) | | (8,059 | ) |
| Total funded status | |
| ($4,495 | ) | |
| ($2,851 | ) | |
| ($2,128 | ) | |
| ($476 | ) | |
| ($9,567 | ) | |
| ($4,694 | ) | |
| ($2,550 | ) | |
| ($2,185 | ) | |
| ($468 | ) | |
| ($8,832 | ) |
| Regulatory asset/(liability) | |
| $2,368 |
| |
| $696 |
| |
| $942 |
| |
| ($65 | ) | |
| $296 |
| |
| $2,356 |
| |
| $544 |
| |
| $883 |
| |
| ($136 | ) | |
| ($333 | ) |
| Accumulated other comprehensive income (before taxes) | |
| $— |
| |
| $98 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $41 |
| |
| $— |
| |
| $— |
| |
| $— |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Reclassification out of Accumulated Other Comprehensive Income (Loss)
Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2015:
2016:
| | | | Qualified
Pension
Costs | | Other
Postretirement
Costs | | Non-Qualified
Pension Costs | | Total | Qualified Pension Costs | | Other Postretirement Costs | | Non-Qualified Pension Costs | | Total |
| | (In Thousands) | (In Thousands) |
| Entergy | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| ($1,557 | ) | |
| $25,905 |
| |
| ($428 | ) | |
| $23,920 |
|
| ($1,079 | ) | |
| $30,949 |
| |
| ($456 | ) | |
| $29,414 |
|
| Acceleration of prior service cost due to curtailment | (374 | ) | | — |
| | — |
| | (374 | ) | (1,045 | ) | | — |
| | — |
| | (1,045 | ) |
| Amortization of loss | (50,508 | ) | | (17,613 | ) | | (2,175 | ) | | (70,296 | ) | (49,930 | ) | | (8,248 | ) | | (2,515 | ) | | (60,693 | ) |
| Settlement loss | — |
| | — |
| | (1,401 | ) | | (1,401 | ) | — |
| | — |
| | (2,007 | ) | | (2,007 | ) |
| |
| ($52,439 | ) | |
| $8,292 |
| |
| ($4,004 | ) | |
| ($48,151 | ) |
| ($52,054 | ) | |
| $22,701 |
| |
| ($4,978 | ) | |
| ($34,331 | ) |
| Entergy Louisiana | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| $— |
| |
| $7,467 |
| |
| ($3 | ) | |
| $7,464 |
|
| $— |
| |
| $7,787 |
| |
| ($1 | ) | |
| $7,786 |
|
| Amortization of loss | (3,003 | ) | | (7,118 | ) | | (19 | ) | | (10,140 | ) | (3,345 | ) | | (2,926 | ) | | (10 | ) | | (6,281 | ) |
| Settlement loss | — |
| | — |
| | (14 | ) | | (14 | ) | |
| |
| ($3,003 | ) | |
| $349 |
| |
| ($36 | ) | |
| ($2,690 | ) |
| ($3,345 | ) | |
| $4,861 |
| |
| ($11 | ) | |
| $1,505 |
|
Entergy and Entergy Louisiana reclassified the following costs out of accumulated other comprehensive income (loss) (before taxes and including amounts capitalized) as of December 31, 2014:2015:
| | | | Qualified
Pension
Costs | | Other
Postretirement
Costs | | Non-Qualified
Pension Costs | | Total | Qualified Pension Costs | | Other Postretirement Costs | | Non-Qualified Pension Costs | | Total |
| | (In Thousands) | (In Thousands) |
| Entergy | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| ($1,559 | ) |
|
| $22,280 |
| |
| ($427 | ) | |
| $20,294 |
|
| ($1,557 | ) |
|
| $25,905 |
| |
| ($428 | ) | |
| $23,920 |
|
| Acceleration of prior service cost due to curtailment | | (374 | ) | | — |
| | — |
| | (374 | ) |
| Amortization of loss | (26,934 | ) | | (6,689 | ) | | (2,213 | ) | | (35,836 | ) | (50,508 | ) | | (17,613 | ) | | (2,175 | ) | | (70,296 | ) |
| Settlement loss | — |
| | — |
| | (3,643 | ) | | (3,643 | ) | — |
| | — |
| | (1,401 | ) | | (1,401 | ) |
| |
| ($28,493 | ) | |
| $15,591 |
| |
| ($6,283 | ) | |
| ($19,185 | ) |
| ($52,439 | ) | |
| $8,292 |
| |
| ($4,004 | ) | |
| ($48,151 | ) |
| Entergy Louisiana | | | | | | | | | | | | | | |
| Amortization of prior service cost |
| $— |
|
|
| $5,614 |
| |
| $— |
| |
| $5,614 |
|
| $— |
|
|
| $7,467 |
| |
| ($3 | ) | |
| $7,464 |
|
| Amortization of loss | (1,911 | ) | | (2,723 | ) | | (3 | ) | | (4,637 | ) | (3,003 | ) | | (7,118 | ) | | (19 | ) | | (10,140 | ) |
| Settlement loss | | — |
| | — |
| | (14 | ) | | (14 | ) |
| |
| ($1,911 | ) | |
| $2,891 |
| |
| ($3 | ) | |
| $977 |
|
| ($3,003 | ) | |
| $349 |
| |
| ($36 | ) | |
| ($2,690 | ) |
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 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 Louisiana recovers other postretirement
Entergy Corporation and Subsidiaries
Notes to Financial Statements
benefit obligations are recorded as other comprehensive income. Entergy Louisiana recovers other postretirement benefit costs on a pay-as-you-go basis and records the unrecognized prior service cost, gains and losses, and transition obligation for its other postretirement benefit obligation as other comprehensive income. Accounting standards also require 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’ 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.
In the optimization 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 target asset allocation for pension adjusts dynamically based on the pension plans’ funded status. The current targets are shown below. The expectation is that the allocation to fixed income securities will increase as the pension plans’ funded status increases. The following ranges were established to produce an acceptable, economically efficient plan to manage around the targets.
The target and range asset allocation for postretirement assets reflects recommendations made in the latest optimization study.
Entergy’s qualified pension and postretirement weighted-average asset allocations by asset category at December 31, 20152016 and 20142015 and the target asset allocation and ranges are as follows:
| | Pension Asset Allocation | | Target | | Range | | Actual 2015 | | Actual 2014 | | Target | | Range | | Actual 2016 | | Actual 2015 |
| Domestic Equity Securities | | 45% | | 34% | to | 53% | | 45% | | 45% | | 45% | | 37% | to | 53% | | 46% | | 45% |
| International Equity Securities | | 20% | | 16% | to | 24% | | 19% | | 19% | | 20% | | 16% | to | 24% | | 20% | | 19% |
| Fixed Income Securities | | 35% | | 31% | to | 41% | | 35% | | 35% | | 35% | | 32% | to | 38% | | 33% | | 35% |
| Other | | 0% | | 0% | to | 10% | | 1% | | 1% | | 0% | | 0% | to | 10% | | 1% | | 1% |
| | Postretirement Asset Allocation | Non-Taxable and Taxable | Non-Taxable and Taxable |
| |
Target |
Range | Actual 2015 | Actual 2014 | Target | Range | Actual 2016 | Actual 2015 |
| Domestic Equity Securities | 39% | 34% | to | 44% | 40% | 42% | 39% | 34% | to | 44% | 40% |
| International Equity Securities | 26% | 21% | to | 31% | 24% | 25% | 26% | 21% | to | 31% | 27% | 24% |
| Fixed Income Securities | 35% | 30% | to | 40% | 36% | 33% | 35% | 30% | to | 40% | 33% | 36% |
| Other | 0% | to | 5% | 0% | 0% | to | 5% | 0% |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 some investment managers.
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 assets. 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), and 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, 2015,2016, 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 credit risk in Entergy’s pension and other postretirement benefit plan assets.
Fair Value Measurements
Accounting standards provide the framework for measuring fair value. That framework provides a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (level(Level 1 measurements) and the lowest priority to unobservable inputs (level(Level 3 measurements).
Effective first quarter 2016, Entergy retrospectively adopted ASU 2015-07, which simplifies the disclosure for fair value investments by removing the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. For all periods presented investments which are valued using the net asset value per share as a practical expedient have not been assigned a level and are presented within the fair value tables only as a reconciling item to the total fair value of investments.
The three levels of the fair value hierarchy are 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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, measured at fair value on a recurring basis at December 31, 2015,2016, and December 31, 2014,2015, 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 Defined Benefit Pension Plan Trusts
| | | 2015 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Short-term investments | | |
| $— |
| |
| $3,610 |
| (a) |
| $— |
| |
| $3,610 |
|
| Equity securities: | | | | | | | | | | | | | | | | |
| Corporate stocks: | | | | | | | | | | | | | | | | |
| Preferred | |
| $6,409 |
| (b) |
| $— |
| (a) |
| $— |
| |
| $6,409 |
| | 6,423 |
| (b) | — |
| | — |
| | 6,423 |
|
| Common | | 686,335 |
| (b) | 95 |
| | — |
| | 686,430 |
| | 745,715 |
| (b) | 39 |
| (b) | — |
| | 745,754 |
|
| Common collective trusts | | — |
| | 1,873,218 |
| (c) | — |
| | 1,873,218 |
| |
| 103-12 investment entities | | — |
| | 283,288 |
| (h) | — |
| | 283,288 |
| |
| Common collective trusts (c) | | | — |
| | — |
| | — |
| | 2,072,743 |
|
| 103-12 investment entities (h) | | |
| |
| |
| | 335,818 |
|
| Registered investment companies | | | 258,879 |
| (d) | — |
| | — |
| | 258,879 |
|
| Fixed income securities: | | | | | | | | | | | | | | | | |
| U.S. Government securities | | 1,879 |
| (b) | 343,805 |
| (a) | — |
| | 345,684 |
| | 136 |
| (b) | 370,545 |
| (a) | — |
| | 370,681 |
|
| Corporate debt instruments | | — |
| | 595,862 |
| (a) | — |
| | 595,862 |
| | — |
| | 630,726 |
| (a) | — |
| | 630,726 |
|
| Registered investment companies | | 255,720 |
| (d) | 547,208 |
| (e) | — |
| | 802,928 |
| |
| Registered investment companies (e) | | | 35,216 |
| (d) | 2,695 |
| (d) | — |
| | 640,836 |
|
| Other | | — |
| | 114,215 |
| (f) | — |
| | 114,215 |
| | 34 |
| (f) | 105,613 |
| (f) | — |
| | 105,647 |
|
| Other: | | | | | | | | | | | | | | | | |
| Insurance company general account (unallocated contracts) | | — |
| | 35,998 |
| (g) | — |
| | 35,998 |
| | — |
| | 37,111 |
| (g) | — |
| | 37,111 |
|
| Total investments | |
| $950,343 |
| |
| $3,793,689 |
| |
| $— |
| |
| $4,744,032 |
| |
| $1,046,403 |
| |
| $1,150,339 |
| |
| $— |
| |
| $5,208,228 |
|
| Cash | | | | | | | | 373 |
| | | | | | | | 929 |
|
| Other pending transactions | | | | | | | | 1,124 |
| | | | | | | | 8,869 |
|
| Less: Other postretirement assets included in total investments | | | | | | | | (38,096 | ) | | | | | | | | (46,824 | ) |
| Total fair value of qualified pension assets | | | | | | | |
| $4,707,433 |
| | | | | | | |
| $5,171,202 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2015 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Equity securities: | | | | | | | | | | | | | | | | |
| Corporate stocks: | | | | | | | | | | | | | | | | |
| Preferred | |
| $10,017 |
| (b) |
| $— |
| (a) |
| $— |
| |
| $10,017 |
| |
| $6,409 |
| (b) |
| $— |
| |
| $— |
| |
| $6,409 |
|
| Common | | 717,685 |
| (b) | 97 |
| | — |
| | 717,782 |
| | 686,335 |
| (b) | 95 |
| (b) | — |
| | 686,430 |
|
Common collective trusts | | — |
| | 1,886,897 |
| (c) | — |
| | 1,886,897 |
| |
|
| |
|
| |
|
| | 1,873,218 |
|
103-12 investment entities | | — |
| | 259,995 |
| | — |
| | 259,995 |
| |
| |
| |
| | 283,288 |
|
| Registered investment companies | | | 202,282 |
| (d) | — |
| | — |
| | 202,282 |
|
| Fixed income securities: | | | | | | | | | | | | | | | | |
| U.S. Government securities | | 240 |
| (b) | 400,059 |
| (a) | — |
| | 400,299 |
| | 1,879 |
| (b) | 343,805 |
| (a) | — |
| | 345,684 |
|
| Corporate debt instruments | | — |
| | 548,788 |
| (a) | — |
| | 548,788 |
| | — |
| | 595,862 |
| (a) | — |
| | 595,862 |
|
| Registered investment companies | | 286,534 |
| (d) | 576,641 |
| (e) | — |
| | 863,175 |
| |
| Registered investment companies (e) | | | 53,438 |
| (d) | 2,685 |
| (d) | — |
| | 600,646 |
|
| Other | | — |
| | 130,295 |
| (f) | — |
| | 130,295 |
| | — |
| | 114,215 |
| (f) | — |
| | 114,215 |
|
| Other: | | | | | | | | | | | | | | | | |
| Insurance company general account (unallocated contracts) | | — |
| | 37,818 |
| (g) | — |
| | 37,818 |
| | — |
| | 35,998 |
| (g) | — |
| | 35,998 |
|
| Total investments | |
| $1,014,476 |
| |
| $3,840,590 |
| |
| $— |
| |
| $4,855,066 |
| |
| $950,343 |
| |
| $1,092,660 |
| |
| $— |
| |
| $4,744,032 |
|
| Cash | | | | | | | | 495 |
| | | | | | | | 373 |
|
| Other pending transactions | | | | | | | | 7,359 |
| | | | | | | | 1,124 |
|
| Less: Other postretirement assets included in total investments | | | | | | | | (34,954 | ) | | | | | | | | (38,096 | ) |
| Total fair value of qualified pension assets | | | | | | | |
| $4,827,966 |
| | | | | | | |
| $4,707,433 |
|
Other Postretirement Trusts
| | | 2015 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Equity securities: | | | | | | | | | | | | | | | | |
Common collective trust | |
| $— |
| |
| $348,604 |
| (c) |
| $— |
| |
| $348,604 |
| | | | | | | |
| $368,704 |
|
| Fixed income securities: | | | | | | | | |
| | | | | | | | |
|
| U.S. Government securities | | 33,789 |
| (b) | 42,222 |
| (a) | — |
| | 76,011 |
| | 30,632 |
| (b) | 43,097 |
| (a) | — |
| | 73,729 |
|
| Corporate debt instruments | | — |
| | 62,629 |
| (a) | — |
| | 62,629 |
| | — |
| | 58,787 |
| (a) | — |
| | 58,787 |
|
| Registered investment companies | | 3,572 |
| (d) | — |
| | — |
| | 3,572 |
| | 3,123 |
| (d) | — |
| | — |
| | 3,123 |
|
| Other | | — |
| | 49,677 |
| (f) | — |
| | 49,677 |
| | — |
| | 45,389 |
| (f) | — |
| | 45,389 |
|
| Total investments | |
| $37,361 |
| |
| $503,132 |
| |
| $— |
| |
| $540,493 |
| |
| $33,755 |
| |
| $147,273 |
| |
| $— |
| |
| $549,732 |
|
| Other pending transactions | | | | | | | | 480 |
| | | | | | | | 104 |
|
| Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 38,096 |
| | | | | | | | 46,824 |
|
| Total fair value of other postretirement assets | | | | | | | |
| $579,069 |
| | | | | | | |
| $596,660 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2015 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Thousands) | | (In Thousands) |
| Equity securities: | | | | | | | | | | | | | | | | |
Common collective trust | |
| $— |
| |
| $370,228 |
| (c) |
| $— |
| |
| $370,228 |
| | | | | | | |
| $348,604 |
|
| Fixed income securities: | | | | | | | | |
| | | | | | | | |
|
| U.S. Government securities | | 36,306 |
| (b) | 45,618 |
| (a) | — |
| | 81,924 |
| | 33,789 |
| (b) | 42,222 |
| (a) | — |
| | 76,011 |
|
| Corporate debt instruments | | — |
| | 57,830 |
| (a) | — |
| | 57,830 |
| | — |
| | 62,629 |
| (a) | — |
| | 62,629 |
|
| Registered investment companies | | 5,558 |
| (d) | — |
| | — |
| | 5,558 |
| | 3,572 |
| (d) | — |
| | — |
| | 3,572 |
|
| Other | | — |
| | 46,968 |
| (f) | — |
| | 46,968 |
| | — |
| | 49,677 |
| (f) | — |
| | 49,677 |
|
| Total investments | |
| $41,864 |
| |
| $520,644 |
| |
| $— |
| |
| $562,508 |
| |
| $37,361 |
| |
| $154,528 |
| |
| $— |
| |
| $540,493 |
|
| Other pending transactions | | | | | | | | 165 |
| | | | | | | | 480 |
|
| Plus: Other postretirement assets included in the investments of the qualified pension trust | | | | | | | | 34,954 |
| | | | | | | | 38,096 |
|
| Total fair value of other postretirement assets | | | | | | | |
| $597,627 |
| | | | | | | |
| $579,069 |
|
| |
| (a) | Certain preferred stocks and certain fixed income debt securities (corporate, government, and securitized) are stated at fair value as determined by broker quotes. |
| |
| (b) | Common stocks, certain preferred stocks, and certain fixed income debt securities (government) 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 common collective trusts estimate fair value. Certain of these common collective trusts are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
| |
| (d) | The registeredRegistered investment company is acompanies are money market mutual fundfunds with a stable net asset value of one dollar per share. Registered investment companies may hold investments in domestic and international bond markets or domestic equities and estimate fair value using net asset value per share. |
| |
| (e) | TheCertain of these registered investment company holds investments in domesticcompanies are not publicly quoted, and international bond markets and estimates fair valueare valued by the fund administrators using net asset value per share.as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
| |
| (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. |
| |
| (h) | 103-12 investment entities hold investments in accordance with stated objectives. The investment strategy of the investment entities is to capture the growth potential of international equity markets by replicating the performance of a specified index. Net asset value per share of the 103-12 investment entities estimate fair value.value using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. |
Accumulated Pension Benefit Obligation
The accumulated benefit obligation for Entergy’s qualified pension plans was $6.3 billion and $6.6 billion at December 31, 2015 and 2014, respectively.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The qualified pension accumulated benefit obligation for each of the Registrant Subsidiaries for their employees as of December 31, 2015 and 2014 was as follows:
|
| | | | | | | |
| | December 31, |
| | 2015 | | 2014 |
| | (In Thousands) |
| Entergy Arkansas |
| $1,309,903 |
| |
| $1,379,108 |
|
| Entergy Louisiana |
| $1,436,535 |
| |
| $1,523,691 |
|
| Entergy Mississippi |
| $379,775 |
| |
| $399,300 |
|
| Entergy New Orleans |
| $176,692 |
| |
| $186,473 |
|
| Entergy Texas |
| $359,687 |
| |
| $391,296 |
|
| System Energy |
| $286,917 |
| |
| $305,556 |
|
Estimated Future Benefit Payments
Based upon the assumptions used to measure Entergy’s qualified pension and other postretirement benefit obligations at December 31, 2015,2016, 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:
| | | | Estimated Future Benefits Payments | | | Estimated Future Benefits Payments | | |
| | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts | Qualified Pension | | Non-Qualified Pension | | Other Postretirement (before Medicare Subsidy) | | Estimated Future Medicare Subsidy Receipts |
| | (In Thousands) | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | |
| 2016 |
| $287,575 |
| |
| $21,187 |
| |
| $78,016 |
| |
| $381 |
| |
| 2017 |
| $301,880 |
| |
| $10,985 |
| |
| $80,565 |
| |
| $432 |
|
| $316,770 |
| |
| $31,687 |
| |
| $83,638 |
| |
| $330 |
|
| 2018 |
| $317,395 |
| |
| $11,456 |
| |
| $85,034 |
| |
| $1,387 |
|
| $328,101 |
| |
| $12,251 |
| |
| $88,235 |
| |
| $1,069 |
|
| 2019 |
| $334,308 |
| |
| $10,794 |
| |
| $88,803 |
| |
| $1,545 |
|
| $343,982 |
| |
| $11,428 |
| |
| $92,511 |
| |
| $1,204 |
|
| 2020 |
| $351,112 |
| |
| $13,443 |
| |
| $91,540 |
| |
| $1,733 |
|
| $362,642 |
| |
| $13,183 |
| |
| $95,167 |
| |
| $1,357 |
|
| 2021 - 2025 |
| $2,039,411 |
| |
| $80,652 |
| |
| $487,584 |
| |
| $11,672 |
| |
| 2021 | |
| $375,354 |
| |
| $11,321 |
| |
| $98,043 |
| |
| $1,518 |
|
| 2022 - 2026 | |
| $2,128,911 |
| |
| $79,373 |
| |
| $510,419 |
| |
| $10,336 |
|
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 for their employees will be as follows:
| | Estimated Future Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | |
| $71,847 |
| |
| $68,238 |
| |
| $20,061 |
| |
| $8,094 |
| |
| $19,442 |
| |
| $13,043 |
| |
| 2017 | |
| $72,566 |
| |
| $70,537 |
| |
| $20,805 |
| |
| $8,426 |
| |
| $20,185 |
| |
| $13,320 |
| |
| $76,603 |
| |
| $73,648 |
| |
| $21,416 |
| |
| $8,829 |
| |
| $20,614 |
| |
| $14,314 |
|
| 2018 | |
| $73,854 |
| |
| $73,422 |
| |
| $21,544 |
| |
| $8,902 |
| |
| $20,955 |
| |
| $13,791 |
| |
| $77,401 |
| |
| $75,927 |
| |
| $21,944 |
| |
| $9,129 |
| |
| $21,230 |
| |
| $14,681 |
|
| 2019 | |
| $75,442 |
| |
| $76,224 |
| |
| $22,237 |
| |
| $9,321 |
| |
| $21,604 |
| |
| $14,153 |
| |
| $78,484 |
| |
| $78,351 |
| |
| $22,423 |
| |
| $9,467 |
| |
| $21,753 |
| |
| $15,147 |
|
| 2020 | |
| $77,137 |
| |
| $79,554 |
| |
| $23,168 |
| |
| $9,910 |
| |
| $22,438 |
| |
| $14,950 |
| |
| $79,804 |
| |
| $81,148 |
| |
| $23,135 |
| |
| $9,979 |
| |
| $22,429 |
| |
| $15,747 |
|
| 2021 - 2025 | |
| $423,691 |
| |
| $460,606 |
| |
| $127,084 |
| |
| $58,280 |
| |
| $123,521 |
| |
| $89,766 |
| |
| 2021 | | |
| $81,382 |
| |
| $84,705 |
| |
| $23,801 |
| |
| $10,577 |
| |
| $23,048 |
| |
| $16,359 |
|
| 2022 - 2026 | | |
| $436,154 |
| |
| $479,274 |
| |
| $127,886 |
| |
| $60,044 |
| |
| $122,832 |
| |
| $98,295 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Estimated Future Non-Qualified Pension Benefits Payments | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | |
| 2017 | |
| $242 |
| |
| $233 |
| |
| $137 |
| |
| $20 |
| |
| $773 |
|
| 2018 | |
| $351 |
| |
| $222 |
| |
| $126 |
| |
| $20 |
| |
| $741 |
|
| 2019 | |
| $282 |
| |
| $211 |
| |
| $124 |
| |
| $51 |
| |
| $716 |
|
| 2020 | |
| $318 |
| |
| $200 |
| |
| $245 |
| |
| $34 |
| |
| $799 |
|
| 2021 | |
| $282 |
| |
| $189 |
| |
| $167 |
| |
| $36 |
| |
| $690 |
|
| 2022 - 2026 | |
| $2,192 |
| |
| $776 |
| |
| $901 |
| |
| $361 |
| |
| $3,637 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | Estimated Future Non-Qualified Pension Benefits Payments | |
Entergy Arkansas | |
Entergy Louisiana | |
Entergy Mississippi | |
Entergy New Orleans | |
Entergy Texas | |
| Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | |
| $2,128 |
| |
| $237 |
| |
| $119 |
| |
| $19 |
| |
| $773 |
| |
| 2017 | |
| $223 |
| |
| $230 |
| |
| $130 |
| |
| $19 |
| |
| $731 |
| |
| $16,195 |
| |
| $19,284 |
| |
| $4,522 |
| |
| $4,054 |
| |
| $7,137 |
| |
| $3,331 |
|
| 2018 | |
| $217 |
| |
| $222 |
| |
| $119 |
| |
| $19 |
| |
| $702 |
| |
| $16,505 |
| |
| $19,986 |
| |
| $4,772 |
| |
| $4,086 |
| |
| $7,576 |
| |
| $3,392 |
|
| 2019 | |
| $211 |
| |
| $214 |
| |
| $117 |
| |
| $46 |
| |
| $680 |
| |
| $16,524 |
| |
| $20,700 |
| |
| $4,859 |
| |
| $4,126 |
| |
| $7,904 |
| |
| $3,505 |
|
| 2020 | |
| $265 |
| |
| $206 |
| |
| $229 |
| |
| $31 |
| |
| $751 |
| |
| $16,410 |
| |
| $21,218 |
| |
| $5,032 |
| |
| $4,084 |
| |
| $8,155 |
| |
| $3,555 |
|
| 2021 - 2025 | |
| $1,579 |
| |
| $961 |
| |
| $863 |
| |
| $218 |
| |
| $3,255 |
| |
| 2021 | | |
| $16,610 |
| |
| $21,804 |
| |
| $5,192 |
| |
| $4,065 |
| |
| $8,443 |
| |
| $3,706 |
|
| 2022 - 2026 | | |
| $82,670 |
| |
| $114,287 |
| |
| $26,500 |
| |
| $19,532 |
| |
| $42,855 |
| |
| $19,376 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
Estimated Future Other Postretirement Benefits Payments (before Medicare Part D Subsidy) | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) |
| Year(s) | | | | | | | | | | | | |
| 2016 | |
| $16,001 |
| |
| $18,946 |
| |
| $4,106 |
| |
| $3,763 |
| |
| $6,244 |
| |
| $3,051 |
|
| 2017 | |
| $15,925 |
| |
| $19,244 |
| |
| $4,168 |
| |
| $3,755 |
| |
| $6,448 |
| |
| $3,115 |
|
| 2018 | |
| $16,249 |
| |
| $20,046 |
| |
| $4,402 |
| |
| $3,803 |
| |
| $6,864 |
| |
| $3,183 |
|
| 2019 | |
| $16,292 |
| |
| $20,863 |
| |
| $4,509 |
| |
| $3,820 |
| |
| $7,177 |
| |
| $3,290 |
|
| 2020 | |
| $16,221 |
| |
| $21,501 |
| |
| $4,677 |
| |
| $3,785 |
| |
| $7,389 |
| |
| $3,349 |
|
| 2021 - 2025 | |
| $82,430 |
| |
| $115,765 |
| |
| $25,004 |
| |
| $18,266 |
| |
| $38,692 |
| |
| $18,094 |
|
| | Estimated Future Medicare Part D Subsidy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | | (In Thousands) | | (In Thousands) |
| Year(s) | | | | | | | | | | | | | | | | | | | | | | | | |
| 2016 | |
| $86 |
| |
| $89 |
| |
| $31 |
| |
| $22 |
| |
| $36 |
| |
| $11 |
| |
| 2017 | |
| $96 |
| |
| $99 |
| |
| $34 |
| |
| $23 |
| |
| $39 |
| |
| $13 |
| |
| $73 |
| |
| $75 |
| |
| $26 |
| |
| $18 |
| |
| $30 |
| |
| $10 |
|
| 2018 | |
| $305 |
| |
| $313 |
| |
| $107 |
| |
| $70 |
| |
| $120 |
| |
| $44 |
| |
| $235 |
| |
| $242 |
| |
| $83 |
| |
| $53 |
| |
| $93 |
| |
| $33 |
|
| 2019 | |
| $339 |
| |
| $344 |
| |
| $117 |
| |
| $73 |
| |
| $128 |
| |
| $51 |
| |
| $265 |
| |
| $268 |
| |
| $91 |
| |
| $56 |
| |
| $100 |
| |
| $40 |
|
| 2020 | |
| $377 |
| |
| $380 |
| |
| $125 |
| |
| $77 |
| |
| $137 |
| |
| $60 |
| |
| $296 |
| |
| $297 |
| |
| $99 |
| |
| $59 |
| |
| $108 |
| |
| $47 |
|
| 2021 - 2025 | |
| $2,422 |
| |
| $2,487 |
| |
| $774 |
| |
| $430 |
| |
| $832 |
| |
| $465 |
| |
| 2021 | | |
| $325 |
| |
| $330 |
| |
| $107 |
| |
| $61 |
| |
| $115 |
| |
| $54 |
|
| 2022 - 2026 | | |
| $2,119 |
| |
| $2,193 |
| |
| $666 |
| |
| $353 |
| |
| $723 |
| |
| $424 |
|
Contributions
Entergy currently expects to contribute approximately $387.5$408.6 million to its qualified pension plans and approximately $52.6$53.1 million to other postretirement plans in 2016.2017. The expected 20162017 pension and other postretirement plan contributions of the Registrant Subsidiaries for their employees are shown below. The 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
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 for their employees in 2016:2017:
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| Pension Contributions |
| $82,829 |
| |
| $83,907 |
| |
| $19,914 |
| |
| $10,693 |
| |
| $15,771 |
| |
| $20,195 |
|
| $79,386 |
| |
| $87,702 |
| |
| $19,117 |
| |
| $9,904 |
| |
| $17,000 |
| |
| $18,096 |
|
| Other Postretirement Contributions |
| $4,238 |
| |
| $18,946 |
| |
| $— |
| |
| $3,669 |
| |
| $3,231 |
| |
| $— |
|
| $525 |
| |
| $19,284 |
| |
| $140 |
| |
| $3,669 |
| |
| $3,231 |
| |
| $690 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Actuarial Assumptions
The significant actuarial assumptions used in determining the pension PBO and the other postretirement benefit APBO as of December 31, 2016 and 2015 were as follows:
|
| | | |
| | 2016 | | 2015 |
| Weighted-average discount rate: | | | |
| Qualified pension | 4.30% - 4.49% Blended 4.39% | | 4.51% - 4.79% Blended 4.67% |
| Other postretirement | 4.30% | | 4.60% |
| Non-qualified pension | 3.63% | | 3.84% |
| Weighted-average rate of increase in future compensation levels | 3.98% | | 4.23% |
| Assumed health care trend rate: | | | |
| Pre-65 | 6.55% | | 6.75% |
| Post-65 | 7.25% | | 7.55% |
| Ultimate rate | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| | |
| Pre-65 | 2026 | | 2024 |
| Post-65 | 2026 | | 2024 |
The significant actuarial assumptions used in determining the net periodic pension and other postretirement benefit costs for 2016, 2015, and 2014 were as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 | | 2014 |
| Weighted-average discount rate: | | | | | | | | |
| Qualified pension | 4.51% - 4.79% Blended 4.67% | | 4.03% - 4.40% Blended 4.27% | |
| Other postretirement | 4.60% | | 4.23% | |
| Non-qualified pension | 3.84% | | 3.61% | |
| Qualified pension: | | |
| Service cost | | 5.00% | | 4.27% | | 5.14% |
| Interest cost | | 3.90% | | 4.27% | | 5.14% |
| Other postretirement: | | |
| Service cost | | 4.92% | | 4.23% | | 5.05% |
| Interest cost | | 3.78% | | 4.23% | | 5.05% |
| Non-qualified pension: | | |
| Service cost | | 3.65% | | 3.61% | | 4.29% |
| Interest cost | | 3.10% | | 3.61% | | 4.29% |
| Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% | 4.23% | | 4.23% | | 4.23% |
| Expected long-term rate of return on plan assets: | | | | | | |
| Pension assets | | 7.75% | | 8.25% | | 8.50% |
| Other postretirement non-taxable assets | | 7.75% | | 8.05% | | 8.30% |
| Other postretirement taxable assets | | 6.00% | | 6.25% | | 6.50% |
| Assumed health care trend rate: | | |
| Pre-65 | 6.75% | | 7.10% | 6.75% | | 7.10% | | 7.25% |
| Post-65 | 7.55% | | 7.70% | 7.55% | | 7.70% | | 7.00% |
| Ultimate rate | 4.75% | | 4.75% | 4.75% | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| |
| |
| |
|
| Pre-65 | 2024 | | 2023 | 2024 | | 2023 | | 2022 |
| Post-65 | 2024 | | 2023 | 2024 | | 2023 | | 2022 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The significant actuarial assumptions used in determiningIn 2016, Entergy refined its approach to estimating the net periodicservice cost and interest cost components of qualified pension, and other postretirement, and non-qualified pension costs. Under the refined approach, instead of using the weighted-average obligation discount rates at the beginning of the year, 2016 service cost and interest costs’ expected cash flows were discounted by the applicable spot rates. The refinement in approach was a change in accounting estimate and, accordingly, the effect was reflected prospectively. The measurement of the benefit costs for 2015, 2014, and 2013 were as follows:obligation was not affected.
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| Weighted-average discount rate: | | | | | |
| Qualified pension | 4.03% - 4.40% Blended 4.27% | | 5.04% - 5.26% Blended 5.14% | | 4.31% - 4.50% Blended 4.36% |
| Other postretirement | 4.23% | | 5.05% | | 4.36% |
| Non-qualified pension | 3.61% | | 4.29% | | 3.37% |
| Weighted-average rate of increase in future compensation levels | 4.23% | | 4.23% | | 4.23% |
| Expected long-term rate of return on plan assets: | | | | | |
| Pension assets | 8.25% | | 8.50% | | 8.50% |
| Other postretirement tax deferred assets | 8.05% | | 8.30% | | 8.50% |
| Other postretirement taxable assets | 6.25% | | 6.50% | | 6.50% |
| Assumed health care trend rate: | | | | | |
| Pre-65 | 7.10% | | 7.25% | | 7.50% |
| Post-65 | 7.70% | | 7.00% | | 7.25% |
| Ultimate rate | 4.75% | | 4.75% | | 4.75% |
| Year ultimate rate is reached and beyond: |
| |
| |
|
| Pre-65 | 2023 | | 2022 | | 2022 |
| Post-65 | 2023 | | 2022 | | 2022 |
With respect to the mortality assumptions, Entergy used the RP-2014 Employee and HealthHealthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2016 projection scale, in determining its December 31, 2016 pension plans’ PBOs and other postretirement benefit APBO. Entergy used the RP-2014 Employee and Healthy Annuitant Tables (adjusted to base year 2006) with a fully generational MP-2015 projection scale, in determining its December 31, 2015 pension plans’ PBOs and other postretirement benefit APBO. The mortality assumption used in determining Entergy’s December 31, 2014 pension plans’ PBOs and other postretirement benefit APBO was the RP-2014 Employee and Health Annuitant Tables, with a fully generational MP-2014 projection scale.
Entergy’s health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in Entergy’s assumed health care cost trend rate for 2016 would have the following effects:
|
| | | | | | | | | | | | | | | | |
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2016 | | 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 | |
| $173,057 |
| |
| $12,281 |
| |
| ($144,460 | ) | |
| ($9,928 | ) |
The Registrant Subsidiaries’ health care cost trend is affected by both medical cost inflation, and with respect to capped costs, the effects of general inflation. A one percentage point change in the assumed health care cost trend rate for 2015 would have the following effects:
|
| | | | | | | | | | | | | | | | |
| | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2015 | | 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 | |
| $181,998 |
| |
| $19,022 |
| |
| ($150,324 | ) | |
| ($15,071 | ) |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
A one percentage point change in the assumed health care cost trend rate for 20152016 would have the following effects for the Registrant Subsidiaries for their employees:
| | | | | 1 Percentage Point Increase | | 1 Percentage Point Decrease | | 1 Percentage Point Increase | | 1 Percentage Point Decrease |
| 2015 | | 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 | |
| 2016 | | | 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) | | Increase/(Decrease) (In Thousands) |
| Entergy Arkansas | |
| $27,571 |
| |
| $3,112 |
| |
| ($22,839 | ) | |
| ($2,442 | ) | |
| $25,743 |
| |
| $1,609 |
| |
| ($21,520 | ) | |
| ($1,313 | ) |
| Entergy Louisiana | |
| $42,312 |
| |
| $4,132 |
| |
| ($34,837 | ) | |
| ($3,274 | ) | |
| $37,874 |
| |
| $2,910 |
| |
| ($31,510 | ) | |
| ($2,343 | ) |
| Entergy Mississippi | |
| $9,032 |
| |
| $850 |
| |
| ($7,412 | ) | |
| ($668 | ) | |
| $7,997 |
| |
| $625 |
| |
| ($6,710 | ) | |
| ($498 | ) |
| Entergy New Orleans | |
| $4,741 |
| |
| $404 |
| |
| ($3,985 | ) | |
| ($329 | ) | |
| $4,941 |
| |
| $259 |
| |
| ($4,184 | ) | |
| ($214 | ) |
| Entergy Texas | |
| $13,195 |
| |
| $1,055 |
| |
| ($10,991 | ) | |
| ($851 | ) | |
| $14,187 |
| |
| $758 |
| |
| ($11,896 | ) | |
| ($619 | ) |
| System Energy | |
| $7,422 |
| |
| $721 |
| |
| ($6,085 | ) | |
| ($570 | ) | |
| $7,750 |
| |
| $489 |
| |
| ($6,401 | ) | |
| ($394 | ) |
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 certain of its subsidiaries. The participating employing Entergy subsidiary makes matching contributions to the System Savings Plan for all eligible participating employees in an amount equal to either 70% or 100% of the participants’ basic contributions, up to 6% of their eligible earnings per pay period. The matching contribution is allocated to investments as directed by the employee.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy also sponsors the Savings Plan of Entergy Corporation and Subsidiaries IV (established in March 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 certain of its subsidiaries.
Entergy’s subsidiaries’ contributions to defined contribution plans collectively were $47 million in 2016, $44.4 million in 2015, and $43.3 million in 2014, and $44.5 million in 2013.2014. The majority of the contributions were to the System Savings Plan.
The Registrant Subsidiaries’ 2016, 2015, 2014, and 20132014 contributions to defined contribution plans for their employees were as follows:
| | Year | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | | (In Thousands) | | (In Thousands) |
| 2016 | | |
| $3,528 |
| |
| $4,746 |
| |
| $1,997 |
| |
| $708 |
| |
| $1,778 |
|
| 2015 | |
| $3,242 |
| |
| $4,324 |
| |
| $1,920 |
| |
| $721 |
| |
| $1,620 |
| |
| $3,242 |
| |
| $4,324 |
| |
| $1,920 |
| |
| $721 |
| |
| $1,620 |
|
| 2014 | |
| $3,044 |
| |
| $4,133 |
| |
| $1,855 |
| |
| $710 |
| |
| $1,563 |
| |
| $3,044 |
| |
| $4,133 |
| |
| $1,855 |
| |
| $710 |
| |
| $1,563 |
|
| 2013 | |
| $3,351 |
| |
| $4,299 |
| |
| $1,954 |
| |
| $769 |
| |
| $1,616 |
| |
NOTE 12. STOCK-BASED COMPENSATION (Entergy Corporation)
Entergy grants stock options, restricted stock, performance units, and restricted stock unit 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 888,602 authorized
Entergy Corporation and Subsidiaries
Notes to Financial Statements
shares remaining for long-term incentive and restricted unit awards as ofexpired December 31, 2015.2016. Effective January 1, 2007, Entergy’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 issuedwere available for issuance from the 2007 Plan for stock-based awards iswas 7,000,000 with no more than 2,000,000 available for non-option grants. The 2007 Plan, which only appliesapplied to awards made on or aftergranted between January 1, 2007 and May 5, 2011, will expire after 10 years. As of December 31, 2015, there were 1,104,547 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 issuedwere available for issuance from the 2011 Plan for stock-based awards iswas 5,500,000 with no more than 2,000,000 available for incentive stock option grants. The 2011 Plan, which only appliesapplied to awards made on or aftergranted between May 6, 2011 and May 7, 2015, will expire after 10 years. As of December 31, 2015, there were 720,775 authorized shares remaining for stock-based awards, including 2,000,000 for incentive stock option grants. Effective May 8, 2015, Entergy’s shareholders approved the 2015 Equity Ownership and Long-Term Cash Incentive Plan (2015 Plan). The maximum number of common shares that can be issued from the 2015 Plan for stock-based awards is 6,900,000 with no more than 1,500,000 available for incentive stock option grants. The 2015 Plan, which only applies to awards granted on or after May 6, 2011, will expire after 10 years. As of December 31, 2015,2016, there were 6,771,6865,192,463 authorized shares remaining for stock-based awards, including 1,500,000 for incentive 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 ten10 years after the date of the grant if they are not exercised.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table includes financial information for stock options for each of the years presented:
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $4.3 | | $4.1 | | $4.1 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $1.6 | | $1.6 | | $1.6 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.7 | | $0.7 | | $0.7 |
|
| | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $4.4 | | $4.3 | | $4.1 |
| Tax benefit recognized in Entergy’s consolidated net income | $1.7 | | $1.6 | | $1.6 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.7 | | $0.7 | | $0.7 |
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:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| Stock price volatility | 23.62% | | 24.67% | | 24.61% | 20.38% | | 23.62% | | 24.67% |
| Expected term in years | 7.06 | | 6.95 | | 6.69 | 7.25 | | 7.06 | | 6.95 |
| Risk-free interest rate | 1.59% | | 2.16% | | 1.31% | 1.77% | | 1.59% | | 2.16% |
| Dividend yield | 4.50% | | 4.75% | | 4.75% | 4.50% | | 4.50% | | 4.75% |
| Dividend payment per share | $3.34 | | $3.32 | | $3.32 | $3.42 | | $3.34 | | $3.32 |
Stock price volatility is calculated based upon the daily public stock price volatility of Entergy Corporation common stock over a period equal to the 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 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 net-of-tax net profit upon exercise of the option to be held in Entergy Corporation
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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.
A summary of stock option activity for the year ended December 31, 20152016 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, 2015 | 7,281,396 |
| | $83.25 | | | | |
| Options granted | 456,100 |
| | $89.90 | | | | |
| Options exercised | (334,274 | ) | | $71.45 | | | | |
| Options forfeited/expired | (3,402 | ) | | $90.49 | | | | |
| Options outstanding as of December 31, 2015 | 7,399,820 |
| | $84.19 | | $— | | 3.7 years |
| Options exercisable as of December 31, 2015 | 6,392,457 |
| | $85.57 | | $— | | 3.0 years |
Weighted-average grant-date fair value of options granted during 2015 | $11.41 | | | | | | |
|
| | | | | | | | |
| | Number of Options | | Weighted- Average Exercise Price | | Aggregate Intrinsic Value | | Weighted- Average Contractual Life |
| Options outstanding as of January 1, 2016 | 7,399,820 |
| | $84.19 | | | | |
| Options granted | 696,900 |
| | $70.56 | | | | |
| Options exercised | (488,131 | ) | | $67.83 | | | | |
| Options forfeited/expired | (471,379 | ) | | $69.99 | | | | |
| Options outstanding as of December 31, 2016 | 7,137,210 |
| | $84.91 | | $— | | 3.35 years |
| Options exercisable as of December 31, 2016 | 6,011,816 |
| | $86.96 | | $— | | 2.38 years |
| Weighted-average grant-date fair value of options granted during 2016 | $7.40 | | | | | | |
The weighted-average grant-date fair value of options granted during the year was $11.41 for 2015 and $8.71 for 2014 and $8.00 for 2013.2014. The total intrinsic value of stock options exercised was $5.1$5 million during 2016, $5 million during 2015, $25.5and $26 million during 2014, and $5.7 million during 2013.2014. The intrinsic value, which has no effect on net income, of the outstanding stock options exercised is calculated by the positive difference in Entergy Corporation’s common stock price onbetween the date of exercise and theweighted average exercise price of the stock options granted.granted and Entergy Corporation’s common stock price as of December 31, 2016. Because Entergy’s year-end stock
Entergy Corporation and Subsidiaries
Notes to Financial Statements
price was less than the weighted average exercise price, the aggregate intrinsic value of outstanding stock options outstanding as of December 31, 20152016 was zero. The intrinsic value of “in the money” stock options is $5$11 million as of December 31, 2015.2016. 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 $5 million during 2016, $4 million during 2015, and $4 million during 2014, and $11 million during 2013.2014. Cash received from option exercises was $23.9$33 million for the year ended December 31, 2015.2016. The tax benefits realized from options exercised was $1.9$2 million for the year ended December 31, 2015.2016.
The following table summarizes information about stock options outstanding as of December 31, 2015:2016:
| | | | | | Options Outstanding | | Options Exercisable | | | Options Outstanding | | Options Exercisable |
| Range of | Range of | | As of | | Weighted-Average Remaining Contractual Life-Yrs. | | Weighted Average Exercise Price | | Number Exercisable as of | | Weighted Average Exercise Price | Range of | | As of | | Weighted-Average Remaining Contractual Life-Yrs. | | Weighted Average Exercise Price | | Number Exercisable as of | | Weighted Average Exercise Price |
| Exercise Prices | Exercise Prices | | 12/31/2015 | | 12/31/2015 | | Exercise Prices | | 12/31/2016 | | 12/31/2016 | |
| $51 | - | $64.99 | | 1,100,272 |
| | 7.62 | | $63.82 | | 546,009 |
| | $64.07 | $51 | - | $64.99 | | 798,308 |
| | 6.68 | | $63.75 | | 627,893 |
| | $63.90 |
| $65 | - | $78.99 | | 2,798,432 |
| | 3.62 | | $74.51 | | 2,798,432 |
| | $74.51 | $65 | - | $78.99 | | 2,853,753 |
| | 4.66 | | $74.47 | | 2,161,853 |
| | $75.72 |
| $79 | - | $91.99 | | 2,059,516 |
| | 2.84 | | $91.39 | | 1,606,416 |
| | $91.82 | $79 | - | $91.99 | | 2,050,549 |
| | 1.84 | | $91.40 | | 1,787,470 |
| | $91.62 |
| $92 | - | $108.20 | | 1,441,600 |
| | 2.06 | | $108.20 | | 1,441,600 |
| | $108.20 | $92 | - | $108.20 | | 1,434,600 |
| | 1.06 | | $108.20 | | 1,434,600 |
| | $108.20 |
| $51 | - | $108.20 | | 7,399,820 |
| | 3.70 | | $84.19 | | 6,392,457 |
| | $85.57 | $51 | - | $108.20 | | 7,137,210 |
| | 3.35 | | $84.91 | | 6,011,816 |
| | $86.96 |
Stock-based compensation cost related to non-vested stock options outstanding as of December 31, 20152016 not yet recognized is approximately $5.6$6 million and is expected to be recognized over a weighted-average period of 1.70 years.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Restricted Stock Awards
In January 20152016 the Board approved and Entergy granted 292,750370,000 restricted stock awards under the 20112015 Equity Ownership and Long-term Cash Incentive Plan. The restricted stock awards were made effective as of January 29, 201528, 2016 and were valued at $89.90$70.56 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 information about the restricted stock awards outstanding as of December 31, 2015:2016:
| | | | Shares | | Weighted-Average Grant Date Fair Value Per Share | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2015 | 674,445 |
| | $64.82 | |
| Outstanding shares at January 1, 2016 | | 642,729 |
| | $75.88 |
| Granted | 323,110 |
| | $88.58 | 401,358 |
| | $70.89 |
| Vested | (325,623 | ) | | $66.09 | (324,862 | ) | | $71.83 |
| Forfeited | (29,203 | ) | | $70.31 | (35,751 | ) | | $77.38 |
| Outstanding shares at December 31, 2015 | 642,729 |
| | $75.88 | |
| Outstanding shares at December 31, 2016 | | 683,474 |
| | $74.80 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table includes financial information for restricted stock for each of the years presented:
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $19.5 | | $19.3 | | $16.4 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $7.5 | | $7.5 | | $6.3 |
| Compensation cost capitalized as part of fixed assets and inventory | $3.9 | | $3.1 | | $2.6 |
|
| | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $19.8 | | $19.5 | | $19.3 |
| Tax benefit recognized in Entergy’s consolidated net income | $7.6 | | $7.5 | | $7.5 |
| Compensation cost capitalized as part of fixed assets and inventory | $4.5 | | $3.9 | | $3.1 |
The total fair value of the restricted stock awards granted was $28.6$29 million, $24.2$29 million, and $25.4$24 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively.
The total fair value of the restricted stock awards vested was $28.7$23 million, $16.5$29 million, and $11$17 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively.
Long-Term Performance Unit Program
Entergy grants long-term incentive awards earned under its stock benefit plans in the form of performance units, which represents the value of one share of Entergy Corporation common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned. Entergy measures performance by assessing Entergy’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. There is no payout for performance that falls within the lowest quartile of performance of the peer companies. For top quartile performance, a maximum payout of 200% of target is earned.
The costs of incentive awards are charged to income over the 3-year period. In January 20152016 the Board approved and Entergy granted 156,017199,800 performance units under the 20112015 Equity Ownership and Long-Term Cash Incentive Plan. The performance units were made effective as of January 29, 2015,28, 2016, and were valued at $99.02$84.52 per
Entergy Corporation and Subsidiaries
Notes to Financial Statements
share. 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 3-year vesting period.
The following table includes information about the long-term performance units outstanding at the target level as of December 31, 2015:2016:
| | | | Shares | | Weighted-Average Grant Date Fair Value Per Share | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2015 | 565,104 |
| | $66.53 | |
| Outstanding shares at January 1, 2016 | | 568,482 |
| | $75.33 |
| Granted | 166,886 |
| | $97.99 | 241,236 |
| | $85.26 |
| Vested | (105,503 | ) | | $67.11 | (54,103 | ) | | $65.36 |
| Forfeited | (58,005 | ) | | $69.73 | (184,064 | ) | | $70.53 |
| Outstanding shares at December 31, 2015 | 568,482 |
| | $75.33 | |
| Outstanding shares at December 31, 2016 | | 571,551 |
| | $82.02 |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table includes financial information for the long-term performance units for each of the years presented:
|
| | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $11.8 | |
| $10.7 |
| |
| $6.0 |
|
| Tax benefit recognized in Entergy’s Consolidated Net Income | $4.5 | |
| $4.1 |
| |
| $2.3 |
|
| Compensation cost capitalized as part of fixed assets and inventory | $2.3 | |
| $1.5 |
| |
| $0.9 |
|
|
| | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $12.3 | |
| $11.8 |
| |
| $10.7 |
|
| Tax benefit recognized in Entergy’s consolidated net income | $4.8 | |
| $4.5 |
| |
| $4.1 |
|
| Compensation cost capitalized as part of fixed assets and inventory | $2.9 | |
| $2.3 |
| |
| $1.5 |
|
The total fair value of the long-term performance units granted was $16.4$21 million, $15.8$16 million and $16.3$16 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively.
In January 2016, Entergy issued 54,103 shares of Entergy Corporation common stock at a share price of $68.09 for awards earned and dividends accrued under the 2013-2015 Long-Term Performance Unit Program. In January 2015, Entergy issued 105,503 shares of Entergy Corporation common stock at a share price of $88.67 for awards earned and dividends accrued under the 2012-2014 Long-Term Performance Unit Program. There was no payout in 2014 and 2013 for the performance units applicable to the 2011-2013 Long-Term Performance Unit Program and 2010-2012 Long-Term Performance Program, respectively.Program.
Restricted Stock Unit Awards
Entergy grants restricted stock unit awards earned under its stock benefit plans in the form of stock units that are subject to time-based restrictions. The restricted stock units may be settled in shares of Entergy Corporation common stock or the cash value of shares of Entergy Corporation common stock at the time of vesting. The costs of restricted stock unit awards are charged to income over the restricted period, which varies from grant to grant. The average vesting period for restricted stock unit awards granted is 42 months. As of December 31, 2015,2016, there were 145,018181,650 unvested restricted stock units that are expected to vest over an average period of 3230 months.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The following table includes information about the restricted stock unit awards outstanding as of December 31, 2015:2016:
| | | | Shares | | Weighted-Average Grant Date Fair Value Per Share | Shares | | Weighted-Average Grant Date Fair Value Per Share |
| Outstanding shares at January 1, 2015 | 98,334 |
| | $73.42 | |
| Outstanding shares at January 1, 2016 | | 145,018 |
| | $72.03 |
| Granted | 57,100 |
| | $69.57 | 70,800 |
| | $76.25 |
| Vested | (10,416 | ) | | $68.73 | (30,668 | ) | | $70.66 |
| Forfeited | — |
| |
| $— |
| (3,500 | ) | | $66.83 |
| Outstanding shares at December 31, 2015 | 145,018 |
| | $72.03 | |
| Outstanding shares at December 31, 2016 | | 181,650 |
| | $74.94 |
The following table includes financial information for restricted stock unit awards for each of the years presented:
|
| | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Millions) |
| Compensation expense included in Entergy’s Consolidated Net Income | $0.9 | | $2.2 | | $1.4 |
| Tax benefit recognized in Entergy’s Consolidated Net Income | $0.4 | | $0.9 | | $0.6 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.3 | | $0.3 | | $0.2 |
|
| | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Millions) |
| Compensation expense included in Entergy’s consolidated net income | $2.2 | | $0.9 | | $2.2 |
| Tax benefit recognized in Entergy’s consolidated net income | $0.8 | | $0.4 | | $0.9 |
| Compensation cost capitalized as part of fixed assets and inventory | $0.4 | | $0.3 | | $0.3 |
The total fair value of the restricted stock unit awards granted was $5 million, $4 million, $3.2 million, and $2.7$3 million for the years ended December 31, 2016, 2015, and 2014, respectively.
Entergy Corporation and 2013, respectively.Subsidiaries
Notes to Financial Statements
The total fair value of the restricted stock unit awards vested was $3.8$2 million, $3.3$4 million, and $2.5$3 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively.
Entergy paid $0.7$2 million, $1.7$1 million, and $2.1$2 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively, for awards under the Restricted Stock Units Awards Plan.
NOTE 13. BUSINESS SEGMENT INFORMATION (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Entergy’s reportable segments as of December 31, 20152016 are Utility and Entergy Wholesale Commodities. Utility includes the generation, transmission, distribution, and sale of electric power in portions of Arkansas, Louisiana, Mississippi, and Texas, and natural gas utility service in portions of Louisiana. Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. 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.
Entergy’s segment financial information is as follows:
|
| | | | | | | | | | | | | | | | | | | | |
| 2016 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| Operating revenues | |
| $8,996,106 |
| |
| $1,849,638 |
| |
| $— |
| |
| ($99 | ) | |
| $10,845,645 |
|
| Asset write-offs, impairments, and related charges | |
| $— |
| |
| $2,835,637 |
| |
| $— |
| |
| $— |
| |
| $2,835,637 |
|
| Depreciation, amortization, & decommissioning | |
| $1,298,043 |
| |
| $374,922 |
| |
| $1,647 |
| |
| $— |
| |
| $1,674,612 |
|
| Interest and investment income | |
| $189,994 |
| |
| $108,466 |
| |
| $27,385 |
| |
| ($180,718 | ) | |
| $145,127 |
|
| Interest expense | |
| $557,546 |
| |
| $22,858 |
| |
| $139,090 |
| |
| ($53,124 | ) | |
| $666,370 |
|
| Income taxes | |
| $424,388 |
| |
| ($1,192,263 | ) | |
| ($49,384 | ) | |
| $— |
| |
| ($817,259 | ) |
| Consolidated net income (loss) | |
| $1,151,133 |
| |
| ($1,493,124 | ) | |
| ($94,917 | ) | |
| ($127,595 | ) | |
| ($564,503 | ) |
| Total assets | |
| $41,098,751 |
| |
| $6,696,038 |
| |
| $1,283,816 |
| |
| ($3,174,171 | ) | |
| $45,904,434 |
|
| Investment in affiliates - at equity | |
| $198 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $198 |
|
| Cash paid for long-lived asset additions | |
| $3,754,225 |
| |
| $289,639 |
| |
| $393 |
| |
| $— |
| |
| $4,044,257 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s segment financial information is as follows:
| | | 2015 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) | | (In Thousands) |
| Operating revenues | |
| $9,451,486 |
| |
| $2,061,827 |
| |
| $— |
| |
| ($62 | ) | |
| $11,513,251 |
| |
| $9,451,486 |
| |
| $2,061,827 |
| |
| $— |
| |
| ($62 | ) | |
| $11,513,251 |
|
| Asset write-offs, impairments, and related charges | |
| $68,672 |
| |
| $2,036,234 |
| |
| $— |
| |
| $— |
| |
| $2,104,906 |
| |
| $68,672 |
| |
| $2,036,234 |
| |
| $— |
| |
| $— |
| |
| $2,104,906 |
|
| Depreciation, amortization, & decommissioning | |
| $1,238,832 |
| |
| $376,560 |
| |
| $2,156 |
| |
| $— |
| |
| $1,617,548 |
| |
| $1,238,832 |
| |
| $376,560 |
| |
| $2,156 |
| |
| $— |
| |
| $1,617,548 |
|
| Interest and investment income | |
| $191,546 |
| |
| $148,654 |
| |
| $34,303 |
| |
| ($187,441 | ) | |
| $187,062 |
| |
| $191,546 |
| |
| $148,654 |
| |
| $34,303 |
| |
| ($187,441 | ) | |
| $187,062 |
|
| Interest expense | |
| $543,132 |
| |
| $26,788 |
| |
| $129,750 |
| |
| ($56,201 | ) | |
| $643,469 |
| |
| $543,132 |
| |
| $26,788 |
| |
| $129,750 |
| |
| ($56,201 | ) | |
| $643,469 |
|
| Income taxes | |
| $16,761 |
| |
| ($610,339 | ) | |
| ($49,349 | ) | |
| $— |
| |
| ($642,927 | ) | |
| $16,761 |
| |
| ($610,339 | ) | |
| ($49,349 | ) | |
| $— |
| |
| ($642,927 | ) |
| Consolidated net income (loss) | |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($74,353 | ) | |
| ($131,240 | ) | |
| ($156,734 | ) | |
| $1,114,516 |
| |
| ($1,065,657 | ) | |
| ($74,353 | ) | |
| ($131,240 | ) | |
| ($156,734 | ) |
| Total assets | |
| $38,356,906 |
| |
| $8,210,183 |
| |
| ($461,505 | ) | |
| ($1,457,903 | ) | |
| $44,647,681 |
| |
| $38,356,906 |
| |
| $8,210,183 |
| |
| ($461,505 | ) | |
| ($1,457,903 | ) | |
| $44,647,681 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $4,142 |
| |
| $— |
| |
| $— |
| |
| $4,341 |
| |
| $199 |
| |
| $4,142 |
| |
| $— |
| |
| $— |
| |
| $4,341 |
|
Cash paid for long-lived asset additions | |
| $2,495,194 |
| |
| $569,824 |
| |
| $236 |
| |
| $— |
| |
| $3,065,254 |
| |
| $2,495,194 |
| |
| $569,824 |
| |
| $236 |
| |
| $— |
| |
| $3,065,254 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| 2014 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) |
| Operating revenues | |
| $9,773,822 |
| |
| $2,719,404 |
| |
| $1,821 |
| |
| ($126 | ) | |
| $12,494,921 |
|
| Asset write-offs, impairments, and related charges | |
| $72,225 |
| |
| $107,527 |
| |
| $— |
| |
| $— |
| |
| $179,752 |
|
| Depreciation, amortization, & decommissioning | |
| $1,170,122 |
| |
| $417,435 |
| |
| $3,702 |
| |
| $— |
| |
| $1,591,259 |
|
| Interest and investment income | |
| $171,217 |
| |
| $113,959 |
| |
| $22,159 |
| |
| ($159,649 | ) | |
| $147,686 |
|
| Interest expense | |
| $531,729 |
| |
| $16,646 |
| |
| $120,908 |
| |
| ($41,776 | ) | |
| $627,507 |
|
| Income taxes | |
| $472,148 |
| |
| $176,988 |
| |
| ($59,539 | ) | |
| $— |
| |
| $589,597 |
|
| Consolidated net income (loss) | |
| $846,496 |
| |
| $294,521 |
| |
| ($62,887 | ) | |
| ($117,873 | ) | |
| $960,257 |
|
| Total assets | |
| $38,186,286 |
| |
| $10,279,500 |
| |
| ($659,207 | ) | |
| ($1,392,124 | ) | |
| $46,414,455 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $36,035 |
| |
| $— |
| |
| $— |
| |
| $36,234 |
|
Cash paid for long-lived asset additions | |
| $2,113,631 |
| |
| $615,021 |
| |
| $87 |
| |
| $— |
| |
| $2,728,739 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2013 | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated | |
| 2014 | | | Utility | | Entergy Wholesale Commodities* | | All Other | | Eliminations | | Consolidated |
| | | (In Thousands) | | (In Thousands) |
| Operating revenues | |
| $9,101,786 |
| |
| $2,312,758 |
| |
| $3,558 |
| |
| ($27,155 | ) | |
| $11,390,947 |
| |
| $9,773,822 |
| |
| $2,719,404 |
| |
| $1,821 |
| |
| ($126 | ) | |
| $12,494,921 |
|
| Asset write-offs, impairments, and related charges | |
| $9,411 |
| |
| $329,336 |
| |
| $2,790 |
| |
| $— |
| |
| $341,537 |
| |
| $72,225 |
| |
| $107,527 |
| |
| $— |
| |
| $— |
| |
| $179,752 |
|
| Depreciation, amortization, & decommissioning | |
| $1,157,843 |
| |
| $341,163 |
| |
| $4,142 |
| |
| $— |
| |
| $1,503,148 |
| |
| $1,170,122 |
| |
| $417,435 |
| |
| $3,702 |
| |
| $— |
| |
| $1,591,259 |
|
| Interest and investment income | |
| $186,724 |
| |
| $137,727 |
| |
| $24,179 |
| |
| ($149,330 | ) | |
| $199,300 |
| |
| $171,217 |
| |
| $113,959 |
| |
| $22,159 |
| |
| ($159,649 | ) | |
| $147,686 |
|
| Interest expense | |
| $509,173 |
| |
| $16,323 |
| |
| $122,291 |
| |
| ($43,750 | ) | |
| $604,037 |
| |
| $531,729 |
| |
| $16,646 |
| |
| $120,908 |
| |
| ($41,776 | ) | |
| $627,507 |
|
| Income taxes | |
| $365,917 |
| |
| ($77,471 | ) | |
| ($62,465 | ) | |
| $— |
| |
| $225,981 |
| |
| $472,148 |
| |
| $176,988 |
| |
| ($59,539 | ) | |
| $— |
| |
| $589,597 |
|
| Consolidated net income (loss) | |
| $846,215 |
| |
| $42,976 |
| |
| ($53,039 | ) | |
| ($105,580 | ) | |
| $730,572 |
| |
| $846,496 |
| |
| $294,521 |
| |
| ($62,887 | ) | |
| ($117,873 | ) | |
| $960,257 |
|
| Total assets | |
| $35,429,568 |
| |
| $9,696,705 |
| |
| ($492,577 | ) | |
| ($1,343,406 | ) | |
| $43,290,290 |
| |
| $38,186,286 |
| |
| $10,279,500 |
| |
| ($659,207 | ) | |
| ($1,392,124 | ) | |
| $46,414,455 |
|
| Investment in affiliates - at equity | |
| $199 |
| |
| $40,151 |
| |
| $— |
| |
| $— |
| |
| $40,350 |
| |
| $199 |
| |
| $36,035 |
| |
| $— |
| |
| $— |
| |
| $36,234 |
|
Cash paid for long-lived asset additions | |
| $2,268,083 |
| |
| $626,322 |
| |
| $49 |
| |
| $— |
| |
| $2,894,454 |
| |
| $2,113,631 |
| |
| $615,021 |
| |
| $87 |
| |
| $— |
| |
| $2,728,739 |
|
Businesses marked with * are sometimes referred to as the “competitive businesses.” Eliminations are primarily intersegment activity. Almost all of Entergy’s goodwill is related to the Utility segment.
Earnings were negatively affected by expensesOn December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In December 2015, Rhode Island State Energy Center, a natural gas-fired combined cycle generating plant, was sold. In October 2015 management announced the intention to shutdown the FitzPatrick plant in 20132017 and the Pilgrim plant in 2019, earlier than previously expected. In 2016 management announced the planned sale of approximately $110 million ($70 million net-of-tax), including approximately $85 million ($55 million net-of-tax)Vermont Yankee in 2018, the planned sale of FitzPatrick in 2017, and the planned termination of the Consumers Energy power purchase agreement for Utilitythe Palisades plant in 2018 and $25 million ($15 million net-of-tax) forthe subsequent plan to shut down the Palisades plant in 2018, earlier than expected. In January 2017 management announced a settlement with New York State to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021, both earlier than expected. Management expects these transactions to result in the cessation of merchant power generation at all Entergy Wholesale Commodities nuclear power plants owned and expenses in 2014 of approximately $20 million ($12 million net-of-tax), including approximately $15 million ($9 million net-of-tax) for Utility and $5 million ($3 million net-of-tax) foroperated by Entergy Wholesale Commodities, recorded in connection with a strategic imperative intendedby 2021. Entergy will continue to optimizehave the organization through a process known as human capital management. In July 2013 management completed a comprehensive review of Entergy’s organization design and processes. This effort resulted in a new internal organization structure, which resulted inobligation to decommission the elimination of approximately 800 employee positions. The restructuring costs associated with this phase of human capital management included implementation costs, severance expenses, benefits-related costs, including pension curtailment losses and special termination benefits, and impairments of corporate property, plant, and equipment. The implementation costs, severance costs, and benefits-related costs are included in “Other operation and maintenance” in the consolidated income statements. The property, plant, and equipment impairments are included in “Asset write-offs, impairments, and related charges” in the consolidated income statements. Total restructuring charges were comprised of the following:nuclear plants owned by Entergy.
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | 2013 | | 2014 | | 2015 |
| | Restructuring Costs | | Paid In Cash | | Non-Cash Portion | | Restructuring Costs | | Paid In Cash | | Paid In Cash |
| | (In Millions) |
| Implementation costs |
| $19 |
| |
| $19 |
| |
| $— |
| |
| $9 |
| |
| $9 |
| |
| $— |
|
| Severance costs | 45 |
| | 6 |
| | — |
| | 11 |
| | 44 |
| | 6 |
|
| Benefits-related costs | 26 |
| | — |
| | 26 |
| | — |
| | — |
| | — |
|
| Property, plant, and equipment impairments | 20 |
| | — |
| | 20 |
| | — |
| | — |
| | — |
|
| Total |
| $110 |
| |
| $25 |
| |
| $46 |
| |
| $20 |
| |
| $53 |
| |
| $6 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
These decisions and transactions resulted in asset impairments, employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions. The employee retention and severance expenses and other benefits-related costs, and contracted economic development contributions are included in "Other operation and maintenance" in the consolidated statement of operations. Total restructuring charges in 2016 were comprised of the following:
|
| | | | | | | | | | | | | | | | |
| | | Restructuring Costs | | Paid In Cash | | Non-Cash Portion | | Remaining Accrual |
| | | (In Millions) |
| Employee retention and severances expenses and other benefits-related costs | |
| $74.2 |
| |
| $0.9 |
| |
| $3.1 |
| |
| $70.2 |
|
Economic development costs
| | 21.3 |
| | — |
| | — |
| | 21.3 |
|
| Total | |
| $95.5 |
| |
| $0.9 |
| |
| $3.1 |
| |
| $91.5 |
|
In addition, Entergy Wholesale Commodities incurred $2.8 billion in 2016 and $2 billion in 2015 of impairment and other related charges associated with these strategic decisions and transactions. See Note 14 to the financial statements for further discussion of these impairment charges.
In addition, Entergy Wholesale Commodities expects to incur employee retention and severance expenses of approximately $100 million in 2017 and approximately $235 million from 2018 through the end of 2021 associated with these strategic transactions.
Geographic Areas
For the years ended December 31, 2016, 2015, 2014, and 2013,2014, the amount of revenue Entergy derived from outside of the United States was insignificant. As of December 31, 20152016 and 2014,2015, 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’ 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.
NOTE 14. EQUITY METHOD INVESTMENTSACQUISITIONS, DISPOSITIONS, AND IMPAIRMENT OF LONG-LIVED ASSETS (Entergy Corporation)Corporation, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans)
As of December 31, 2015, Entergy owns investments in the following companies that it accounts for under the equity method of accounting:
|
| | | | | | |
Investment | | Ownership | | Description |
| | | | | |
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. |
Acquisitions
Following is a reconciliation of Entergy’s investments in equity affiliates:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| Beginning of year |
| $36,234 |
| |
| $40,350 |
| |
| $46,738 |
|
| Loss from the investments | (36,269 | ) | | (5,169 | ) | | (1,702 | ) |
| Other adjustments | 4,376 |
| | 1,053 |
| | (4,686 | ) |
| End of year |
| $4,341 |
| |
| $36,234 |
| |
| $40,350 |
|
LossIn March 2016, Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans purchased the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from the investments in 2015 includes a $36.8 million pre-tax impairment charge resulting from a write-downUnion Power Partners, L.P. The Union Power Station consists of the generating assets of Top Deer, of which Entergy’s owns a 50% interest.
Transactions with equity method investees
four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Entergy Louisiana purchased two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy New Orleans each purchased one power block and a 25% undivided ownership interest in such related assets. The aggregate purchase price for the Union Power Station was approximately $3.2$949 million in 2013 of electricity generated from Entergy’s share of RS Cogen. Entergy Louisiana made no purchases in 2015(approximately $237 million for each power block and 2014 of electricity generated from Entergy’s share of RS Cogen.associated assets).
EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.5 million, $23.1 million, and $22.9 million for 2015, 2014, and 2013, respectively.
Entergy’s operating transactions with its other equity method investees were not significant in 2015, 2014, or 2013.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
NOTE 15. ACQUISITIONS AND DISPOSITIONS (Entergy Corporation)
Acquisitions
Palisades Purchased Power Agreement
Entergy’s purchase of the Palisades plant in 2007 included a unit-contingent, 15-year purchased power agreement (PPA) with Consumers Energy for 100% of the plant’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. For the PPA, which was at below-market prices at the time of the acquisition, Entergy 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’s difference between revenue under the agreement and revenue based on estimated market prices. Amounts amortized to revenue were $13 million in 2016, $15 million in 2015, and $16 million in 2014, and $182014. In December 2016, Entergy announced that it has reached an agreement with Consumers Energy to terminate the PPA early, on May 31, 2018, subject to regulatory approvals. Because of entering into the early termination agreement, Entergy expects to amortize approximately $43 million in 2013. The amounts to be amortizedof the liability to revenue forin 2017 and $29 million to revenue in 2018. The timing of the next five years will be $13 million in 2016, $12 million for 2017, $8 million for 2018, $13 million for 2019,liability amortization could fluctuate further depending upon if, and $15 million for 2020.when, regulatory approval of the early termination agreement is received. See further discussion of the Palisades transaction below.
NYPA Value Sharing Agreements
Entergy’s purchase of the FitzPatrick and Indian Point 3 plants from NYPA included value sharing agreements with NYPA. In October 2007, Entergy 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, Entergy subsidiaries made 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 paid 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’s output was due by January 15 of the following year. Entergy recorded the liability for payments to NYPA as power iswas generated and sold by Indian Point 3 and FitzPatrick. An amount equal to the liability was recorded to the plant asset account as contingent purchase price consideration for the plants. In 2014, and 2013, Entergy Wholesale Commodities recorded approximately $72 million as plant for generation during each of those years. This amount was depreciated over the expected remaining useful life of the plants.generation.
Dispositions
Vermont Yankee
In November 2016, Entergy entered into an agreement to sell 100% of the membership interests in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant and is in the Entergy Wholesale Commodities segment. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of the nuclear decommissioning trust fund and the asset retirement obligation for the spent fuel management and decommissioning of the plant.
Entergy Nuclear Vermont Yankee has an outstanding credit facility with borrowing capacity of $100 million to pay for dry fuel storage costs. This credit facility is guaranteed by Entergy Corporation. At or before closing, a subsidiary of Entergy will assume the obligations under the existing credit facility or enter into a new credit facility and Entergy will guarantee the credit facility. At the closing of the sale transaction, NorthStar will pay $1,000 for the membership interests in Entergy Nuclear Vermont Yankee, and NorthStar will cause Entergy Nuclear Vermont Yankee to issue a promissory note to the Entergy entity selling the membership interests in Entergy Nuclear Vermont Yankee. The amount of the promissory note issued will be equal to the amount drawn under the credit facility or the amount drawn under the new credit facility, plus borrowing fees and costs incurred by Entergy in connection with such facility. The principal amount drawn under the outstanding credit facility was $45 million as of December 31, 2016, and the net book value of Entergy Nuclear Vermont Yankee, including unrealized gains on the decommissioning trust fund, as of December 31, 2016, was approximately $88 million.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018, subject to obtaining necessary regulatory approvals, in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. Entergy Nuclear Vermont Yankee, under NorthStar ownership, will be required to repay the promissory note issued to Entergy with certain of the proceeds from the recovery of damages under its claims against the DOE related to spent nuclear fuel disposal, with any balance remaining due at partial site restoration, subject to extension not to exceed two years from partial site restoration.
The transaction is subject to certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of revised site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments. The transaction is expected to close by the end of 2018, subject to certain conditions, including the condition that Entergy contribute to the decommissioning trust fund if the value is less than provided for in the agreement with NorthStar.
FitzPatrick
In August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon. The transaction is expected to close in the first half of 2017. The purchase price is $100 million and the assumption by Exelon of certain liabilities related to the FitzPatrick plant, with an additional $10 million non-refundable signing fee, which was paid upon the signing of the agreement. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016, including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017. Entergy expects to operate the FitzPatrick plant until the asset purchase agreement closing date. Entergy entered into a reimbursement agreement with Exelon pursuant to which Exelon will reimburse Entergy for specified out-of-pocket costs associated with the refueling and operation of FitzPatrick that otherwise would have been avoided had Entergy shut down FitzPatrick in January 2017. Pursuant to the reimbursement agreement, as of December 31, 2016 Exelon reimbursed Entergy $56 million for nuclear fuel expenses and $41 million for other operation and maintenance expenses associated with preparing to refuel FitzPatrick in 2017. If the asset purchase agreement is terminated, a termination fee of up to $30 million will be payable to Entergy under certain circumstances. If it is consummated, the transaction could result in a gain or loss because of fluctuations in the decommissioning trust fund earnings and asset retirement obligation accretion. Upon the closing of the sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon.
As a result of the agreement and the status of the necessary regulatory approvals, the assets and liabilities associated with the sale of FitzPatrick to Exelon are classified as held for sale on Entergy Corporation and Subsidiaries’ Consolidated Balance Sheet. As of December 31, 2016, the $785 million receivable for the beneficial interest in the decommissioning trust fund within other deferred debits and the $714 million asset retirement obligation within other non-current liabilities are classified as held for sale. The transaction also includes property, plant, and equipment with a net book value of zero.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Top Deer
In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned by Entergy in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for approximately $0.5 million and realized a pre-tax loss of $0.2 million on the sale.
Rhode Island State Energy Center
In December 2015, Entergy sold the Rhode Island State Energy Center, a 583 MW natural gas-fired combined-cycle generating plant owned by Entergy in the Entergy Wholesale Commodities segment. Entergy sold Rhode Island State Energy Center for approximately $490 million and realized a pre-tax gain of $154 million on the sale.
Impairment of Long-lived Assets
2016 Impairment Conclusions
In NovemberDecember 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant after May 2018. The agreement is subject to regulatory approvals. Assuming regulatory approvals are obtained Entergy determined that it will close the Palisades plant on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. As a result of the PPA termination and its intention to shut down the plant, Entergy tested the recoverability of the plant and related assets as of December 31, 2016.
Indian Point 2 and Indian Point 3 have an application pending for renewed NRC licenses. Various parties, including the State of New York, expressed opposition to renewal of the licenses. Under federal law, nuclear power plants may continue to operate beyond their original license expiration dates while their timely filed renewal applications are pending NRC approval. Indian Point 2 reached the expiration date of its original NRC operating license on September 28, 2013, and Indian Point 3 reached the expiration date of its original NRC operating license on December 12, 2015. Upon expiration of their operating licenses, each plant entered into a period of extended operation under the timely renewal rule.
In January 2017, Entergy soldannounced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State has agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also has agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. As a result of its evaluation of alternatives to the continued operation of the Indian Point plants, and taking into consideration the status of negotiations with the State of New York, Entergy Solutions District Energy,tested the recoverability of the plants and related assets as of December 31, 2016.
Under generally accepted accounting principles the determination of an asset’s 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 operations of the plant and pending legal and state regulatory matters, as well as projections of future revenues and costs over the estimated remaining life of the plant.
The tests for Palisades and Indian Point indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets as of December 31, 2016.
As of December 31, 2016 the estimated fair value of the Palisades plant and related long-lived assets is $206 million, while the carrying value was $558 million, resulting in an impairment charge of $352 million. Materials and supplies were evaluated and written down by $48 million. In summary, as of December 31, 2016, the total impairment
Entergy Corporation and Subsidiaries
Notes to Financial Statements
loss and related charges for Palisades is $400 million ($258 million net-of-tax). The pre-impairment carrying value of $558 million includes the effect of a business wholly-owned$129 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.
As of December 31, 2016 the estimated fair value of the Indian Point plants and related long-lived assets is $433 million, while the carrying value was $2,619 million, resulting in an impairment charge of $2,186 million. Materials and supplies were evaluated and written down by $157 million. In summary, as of December 31, 2016, the total impairment loss and related charges for Indian Point is $2,343 million ($1,511 million net-of-tax). The pre-impairment carrying value of $2,619 million includes the effect of a $392 million increase in Indian Point’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Indian Point decommissioning cost revision.
2015 Impairment Conclusions
Entergy determined in October 2015 that it would close FitzPatrick at the end of its current fuel cycle, which was planned for January 27, 2017, because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. This decision came after management’s extensive analysis of whether it was advisable economically to refuel the plant, as scheduled, in the fall of 2016. Entergy also had discussions with the State of New York regarding the future of FitzPatrick. Because of the uncertainty regarding the refueling decision and its implications to the plant’s expected operating life, Entergy tested the recoverability of the plant and related assets as of September 30, 2015. See above for further information on the subsequent decision to sell the FitzPatrick plant.
Entergy determined in October 2015 that it would close Pilgrim no later than June 1, 2019 because of poor market conditions that led to reduced revenues, a poor market design that failed to properly compensate nuclear generators for the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in its “multiple/repetitive degraded cornerstone column” (Column 4) of its Reactor Oversight Process Action Matrix. Because of the uncertainty regarding the plant’s operating life created by the NRC’s decision and management’s analysis of the plant, Entergy tested the recoverability of the plant and related assets as of September 30, 2015.
Due to the announced plant closures in October 2015, as well as the continued challenging market price trend, the high level of investment required to continue to operate the Entergy Wholesale Commodities plants, and the inadequate compensation provided to nuclear generators for their capacity benefits under the current market design, Entergy tested the recoverability of the plant and related assets of the two remaining operating nuclear power generating facilities in the Entergy Wholesale Commodities segmentbusiness, Palisades and Indian Point, in the fourth quarter 2015. For purposes of that ownsevaluation, Entergy considered a number of factors associated with the facilities’ continued operation, including the status of the associated NRC licenses, the status of state regulatory issues, existing power purchase agreements, and operates districtthe supply region in which the nuclear facilities sell energy and capacity.
The tests for FitzPatrick and Pilgrim indicated that the probability-weighted undiscounted net cash flows did not exceed the carrying values of the plants and related assets servingas of September 30, 2015.
The test for Palisades indicated the business districtsprobability-weighted undiscounted net cash flows did not exceed the carrying value of the plant and related assets as of December 31, 2015.
The test for Indian Point indicated that the probability-weighted undiscounted net cash flows exceeded the carrying value of the plant and related assets as of December 31, 2015. As such, the carrying value of Indian Point
Entergy Corporation and Subsidiaries
Notes to Financial Statements
was not impaired as of December 31, 2015. As of December 31, 2015, the net carrying value of Indian Point, including nuclear fuel, was $2,360 million.
As of September 30, 2015, the estimated fair value of the FitzPatrick plant and related long-lived assets was $29 million, while the carrying value was $742 million, resulting in Houstonan impairment charge of $713 million. Materials and New Orleans.supplies were evaluated and written down by $48 million. In addition, FitzPatrick had a contract asset recorded for an agreement between Entergy soldsubsidiaries and NYPA entered when Entergy Solutions District Energysubsidiaries purchased FitzPatrick from NYPA in 2000 and NYPA retained the decommissioning trusts and the decommissioning liabilities. The agreement gave NYPA the right to require the Entergy subsidiaries to assume the decommissioning liability provided that it assigns the decommissioning trust, up to a specified level, to Entergy. If NYPA retained the decommissioning liabilities, the Entergy subsidiaries would perform the decommissioning of the plant at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts. The contract asset represented an estimate of the present value of the difference between the Entergy subsidiaries’ stipulated contract amount for $140decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies. See Note 9 for further discussion of the contract asset. Due to a change in expectation regarding the timing of decommissioning cash flows, the result was a write down of the contract asset from $335 million to $131 million, for a charge of $204 million. In summary, as of September 30, 2015, the impairment and realizedrelated charges for FitzPatrick was $965 million ($624 million net-of-tax).
As of September 30, 2015, the estimated fair value of the Pilgrim plant and related long-lived assets is $65 million, while the carrying value was $718 million, resulting in an impairment charge of $653 million. Materials and supplies were evaluated and written down by $24 million. In summary, as of September 30, 2015, the total impairment loss and related charges for Pilgrim was $677 million ($438 million net-of-tax). The pre-impairment carrying value of $718 million includes the effect of a pre-tax gain$134 million increase in Pilgrim’s estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the change in expectation regarding the timing of $44decommissioning cash flows. See Note 9 to the financial statements for further discussion regarding the Pilgrim decommissioning cost revision.
As of December 31, 2015, the estimated fair value of the Palisades plant and related long-lived assets was $463 million, while the carrying value was $859 million, resulting in an impairment charge of $396 million ($256 million net-of-tax). The pre-impairment carrying value of $859 million includes the effect of a $42 million increase in Palisades’ estimated decommissioning cost liability and the related asset retirement cost asset. The increase in the estimated decommissioning cost liability primarily resulted from the assessment of the estimated decommissioning cash flows that occurred in conjunction with the impairment analysis. See Note 9 to the financial statements for further discussion regarding the Palisades decommissioning cost revision.
2014 Impairment Conclusion
In August 2013, the Board approved a plan to close and decommission Vermont Yankee at the end of its fuel cycle at the end of 2014. As a result of the decision to shut down the plant, Entergy recognized impairment and other related charges during the third quarter 2013 to write down the carrying value of Vermont Yankee and related assets to their fair values. As part of the development of the site assessment study and PSDAR, Entergy obtained a revised decommissioning cost study in the third quarter 2014. The revised estimate, along with reassessment of the assumptions regarding the timing of decommissioning cash flows, resulted in a $101.6 million increase in the decommissioning cost liability and a corresponding impairment charge, recorded in September 2014. See Note 9 to the financial statements for further discussion regarding the Vermont Yankee decommissioning cost revisions.
Overall Regarding All Impairments
The impairments and other related charges are recorded as a separate line item in Entergy’s consolidated statements of operations and are included within the results of the Entergy Wholesale Commodities segment. In addition to the impairments and other related charges, Entergy expects to incur additional charges through 2021 associated with these strategic transactions. See Note 13 to the financial statements for further discussion of these additional charges.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value analyses for FitzPatrick, Indian Point, Pilgrim, and Palisades were performed based on the sale.income approach, a discounted cash flow method, to determine the amount of impairment. The estimates of fair value were based on the prices that Entergy would expect to receive in hypothetical sales of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets to a market participant. In order to determine these prices, 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 plants and related assets, the amount and timing of recoveries from future litigation with the DOE related to spent fuel storage costs, and the expected operating life of the plant. 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, are classified as Level 3 in the fair value hierarchy discussed in Note 15 to the financial statements.
The following table sets forth a description of significant unobservable inputs used in the valuation of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets:
|
| | | | |
| Significant Unobservable Inputs | | Amount | | Weighted Average |
| 2016 | | | | |
| Weighted average cost of capital | | | | |
| Indian Point (a) | | 7.0%-7.5% | | 7.2% |
| Palisades | | 6.5% | | 6.5% |
| | | | | |
| Long-term pre-tax operating margin (cash basis) | | | | |
| Indian Point | | 19.7% | | 19.7% |
| Palisades (b) (c) | | 17.8%-38.8% | | 34.6% |
| | | | | |
| 2015 | | | | |
| Weighted average cost of capital | | | | |
| FitzPatrick | | 7.5% | | 7.5% |
| Pilgrim (d) | | 7.5%-8.0% | | 7.9% |
| Palisades | | 7.5% | | 7.5% |
| | | | | |
| Long-term pre-tax operating margin (cash basis) | | | | |
| FitzPatrick | | 10.2% | | 10.2% |
| Pilgrim (d) | | 2.4%-10.6% | | 8.1% |
| Palisades (b) | | 30.8% | | 30.8% |
| |
| (a) | The cash flows extending through the 2021 shutdown at Indian Point 3 were assigned a higher discount factor to incorporate the increased risk associated with longer operations. |
| |
| (b) | Most of the Palisades output is sold under a 15-year power purchase agreement, entered at the plant’s acquisition in 2007, that originally was scheduled to expire in 2022. The power purchase agreement prices currently exceed market prices and escalate each year, up to $61.50/MWh in 2022. |
| |
| (c) | The fair value of Palisades at December 31, 2016 is based on the probability weighting of whether the PPA will terminate before the originally scheduled termination in 2022. |
| |
| (d) | The fair value of Pilgrim was based on the probability weighting of two potential scenarios. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting group, which reports to the Chief Accounting Officer, was primarily responsible for determining the valuation of the FitzPatrick, Indian Point, Pilgrim, and Palisades plants and related assets, in consultation with external advisors. Entergy’s Accounting Policy group obtained and reviewed information from other Entergy departments with expertise on the various inputs and assumptions that were necessary to calculate the fair values of the asset groups.
NOTE 16.15. RISK MANAGEMENT AND FAIR VALUES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Market Risk
In the normal course of business, Entergy is exposed to a number of market 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 commodity or instrument. All financial and commodity-related instruments, including derivatives, are subject to market risk including commodity price risk, equity price, and interest rate risk. Entergy uses derivatives primarily to mitigate commodity price risk, particularly power price and fuel price risk.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The Utility 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 regulators, the Utility operating companies use derivative instruments to hedge the exposure to price volatility inherent in their purchased power, fuel, and gas purchased for resale costs that are recovered from customers.
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 also sells energy and capacity in the day ahead or spot markets. In addition to its forward physical power and gas contracts, Entergy Wholesale Commodities also uses a combination of financial contracts, including swaps, collars, and options, to mitigate commodity price risk. When the market price falls, the combination of instruments is expected to settle in gains that offset lower revenue from generation, which results in a more predictable cash flow.
Entergy’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’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. Hedging instruments and volumes are chosen based on ability to mitigate risk associated with future energy and capacity prices; however, other considerations are factored into hedge product and volume decisions including corporate liquidity, corporate credit ratings, counterparty credit risk, hedging costs, firm settlement risk, and product availability in the marketplace. 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’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’s objectives.
Derivatives
Some derivative instruments are classified as cash flow hedges due to their financial settlement provisions while others are classified as normal purchase/normal sale transactions due to their physical settlement provisions. Normal purchase/normal sale risk management tools include power purchase and sales agreements, fuel purchase agreements, capacity contracts, and tolling agreements. Financially-settled cash flow hedges can include natural gas and electricity swaps and options and interest rate swaps. Entergy may enter into financially-settled swap and option contracts to manage market risk that may or may not be designated as hedging instruments.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy enters into derivatives to manage natural risks inherent in its physical or financial assets or liabilities. Electricity over-the-counter instruments and futures contracts that financially settle against day-ahead power pool prices are used to manage price exposure for Entergy Wholesale Commodities generation. The maximum length of time over which Entergy is currently hedging the variability in future cash flows with derivatives for forecasted power transactions at December 31, 20152016 is approximately 22.25 years. Planned generation currently under contract from Entergy Wholesale Commodities nuclear power plants is 86%87% for 2016,2017, of which approximately 62%59% is sold under financial derivatives and the remainder under normal purchase/normal sale contracts. Total planned generation for 20162017 is 3627.3 TWh.
Entergy may use standardized master netting agreements to help mitigate the credit risk of derivative instruments. These master agreements facilitate the netting of cash flows associated with a single counterparty and may include collateral requirements. Cash, letters of credit, and parental/affiliate guarantees may be obtained as security from counterparties in order to mitigate credit risk. The collateral agreements require a counterparty to post cash or letters of credit in the event an exposure exceeds an established threshold. The threshold represents an unsecured credit limit, which may be supported by a parental/affiliate guaranty, as determined in accordance with Entergy’s credit policy. In addition, collateral agreements allow for termination and liquidation of all positions in the event of a failure or inability to post collateral.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Certain of the agreements to sell the power produced by Entergy Wholesale Commodities power plants contain provisions that require an Entergy subsidiary to provide credit support to secure its obligations whendepending on the current market prices exceedmark-to-market values of the contracted power prices.contracts. The primary form of credit support to satisfy these requirements is an Entergy Corporation guarantee. As of December 31, 2016, derivative contracts with 3 counterparties were in a liability position (approximately $8 million total). In addition to the corporate guarantee, $2 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties. As of December 31, 2015, derivative contracts with 2 counterparties were in a liability position (approximately $2 million total). In addition to the corporate guarantee,As of December 31, 2015, $9 million in cash collateral was required to be posted by the Entergy subsidiary to its counterparties and $68 million was required to be posted by its counterparties to the Entergy subsidiary. As of December 31, 2014, derivative contracts with 1 counterparty were in a liability position (approximately $1 million total). If the Entergy Corporation credit rating falls below investment grade, the effect of the corporate guarantee is typically ignored and Entergy would have to post collateral equal to the estimated outstanding liability under the contract at the applicable date.
Entergy manages fuel price volatility for its Louisiana jurisdictions (Entergy Louisiana and Entergy New Orleans) and Entergy Mississippi through the purchase of short-term natural gas swaps that financially settle against NYMEX futures. These swaps are marked-to-market through fuel expense with offsetting regulatory assets or liabilities. All benefits or costs of the program are recorded in fuel costs. The notional volumes of these swaps are based on a portion of projected annual exposure to gas for electric generation at Entergy Louisiana and Entergy Mississippi and projected winter purchases for gas distribution at Entergy Louisiana and Entergy New Orleans. The total volume of natural gas swaps outstanding as of December 31, 20152016 is 39,816,00037,970,000 MMBtu for Entergy, including 32,140,00030,940,000 MMBtu for Entergy Louisiana, 7,010,0006,540,000 MMBtu for Entergy Mississippi, and 666,000490,000 MMBtu for Entergy New Orleans. Credit support for these natural gas swaps is covered by master agreements that do not require collateralization based on mark-to-market value, but do carry adequate assurance language that may lead to collateralization requests.
During the second quarter 2015,2016, Entergy participated in the annual FTRfinancial transmission right (FTR) auction process for the MISO planning year of June 1, 20152016 through May 31, 2016.2017. FTRs are derivative instruments which represent economic hedges of future congestion charges that will be incurred in serving Entergy’s customer load. They are not designated as hedging instruments. Entergy initially records FTRs at their estimated fair value and subsequently adjusts the carrying value to their estimated fair value at the end of each accounting period prior to settlement. Unrealized gains or losses on FTRs held by Entergy Wholesale Commodities are included in operating revenues. The Utility operating companies recognize regulatory liabilities or assets for unrealized gains or losses on FTRs. The total volume of FTRs outstanding as of December 31, 20152016 is 46,35546,216 GWh for Entergy, including 9,72610,540 GWh for Entergy Arkansas, 21,38319,467 GWh for Entergy Louisiana, 6,1607,535 GWh for Entergy Mississippi, 3,5172,234 GWh for Entergy New Orleans, and 5,2946,248 GWh for Entergy Texas. Credit support for FTRs held by the Utility operating companies is covered by cash and/or letters of credit issued by each Utility operating company as required by MISO. Credit support for FTRs held
Entergy Corporation and Subsidiaries
Notes to Financial Statements
by Entergy Wholesale Commodities is covered by cash. As of December 31, 2014,2016, letters of credit posted with MISO covered the FTR exposure for Entergy Arkansas and Entergy Mississippi. As of December 31, 2015, no cash or letters of credit were required to be posted for FTR exposure for the Utility operating companies or Entergy Wholesale Commodities, respectively.
The fair values of Entergy’s derivative instruments in the consolidated balance sheet as of December 31, 2016 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.
|
| | | | | | | | | | |
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business |
| | | | | (In Millions) | | |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $25 | | ($14) | | $11 | | Entergy Wholesale Commodities |
| Electricity swaps and options |
| Other deferred debits and other assets (non-current portion) | | $6 | | ($6) | | $— | | Entergy Wholesale Commodities |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $11 | | ($10) | | $1 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $16 | | ($7) | | $9 | | Entergy Wholesale Commodities |
|
| | | | | | | | | | |
| Derivatives not designated as hedging instruments | | | | | | | | | | |
| | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $18 | | ($13) | | $5 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $5 | | ($5) | | $— | | Entergy Wholesale Commodities |
| Natural gas swaps | | Prepayments and other | | $13 | | $— | | $13 | | Utility |
| Financial transmission rights | | Prepayments and other | | $22 | | ($1) | | $21 | | Utility and Entergy Wholesale Commodities |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $18 | | ($17) | | $1 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $4 | | ($4) | | $— | | Entergy Wholesale Commodities |
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, 2015 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.
|
| | | | | | | | | | |
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business |
| | | | | (In Millions) | | |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $173 | | ($34) | | $139 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $17 | | ($2) | | $15 | | Entergy Wholesale Commodities |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $14 | | ($14) | | $— | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $2 | | ($2) | | $— | | Entergy Wholesale Commodities |
|
| | | | | | | | | | |
| Derivatives not designated as hedging instruments | | | | | | | | | | |
| | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $54 | | ($13) | | $41 | | Entergy Wholesale Commodities |
| FTRs | | Prepayments and other | | $24 | | ($1) | | $23 | | Utility and Entergy Wholesale Commodities |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $38 | | ($32) | | $6 | | Entergy Wholesale Commodities |
| Natural gas swaps | | Other current liabilities | | $9 | | $— | | $9 | | 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, 2014 are shown in the table below. Certain investments, including those not designated as hedging instruments, are subject to master netting agreements and are presented in the balance sheet on a net basis in accordance with accounting guidance for derivatives and hedging.
|
| | | | | | | | | | |
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Offset (b) | | Net (c) (d) | | Business |
| | | | | (In Millions) | | |
| | | | | | | | | | | |
| Derivatives designated as hedging instruments | | | | | | | | | | |
| | | | | | | | | | | |
| Assets: | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $149 | | ($53) | | $96 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $48 | | $— | | $48 | | Entergy Wholesale Commodities |
| | | | | | | | | | | |
| Liabilities: | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $24 | | ($24) | | $— | | Entergy Wholesale Commodities |
| | | Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | |
| Assets: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Prepayments and other (current portion) | | $97 | | ($25) | | $72 | | Entergy Wholesale Commodities | | Prepayments and other (current portion) | | $54 | | ($13) | | $41 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other deferred debits and other assets (non-current portion) | | $9 | | ($8) | | $1 | | Entergy Wholesale Commodities | |
| FTRs | | Prepayments and other | | $50 | | ($3) | | $47 | | Utility and Entergy Wholesale Commodities | |
| Financial transmission rights | | | Prepayments and other | | $24 | | ($1) | | $23 | | Utility and Entergy Wholesale Commodities |
| | | | | | | | | | | | | | | | | |
| Liabilities: | | | | | | | | | | | | | | | | |
| Electricity swaps and options | | Other current liabilities (current portion) | | $57 | | ($55) | | $2 | | Entergy Wholesale Commodities | | Other current liabilities (current portion) | | $38 | | ($32) | | $6 | | Entergy Wholesale Commodities |
| Electricity swaps and options | | Other non-current liabilities (non-current portion) | | $8 | | ($8) | | $— | | Entergy Wholesale Commodities | |
| Natural gas swaps | | Other current liabilities | | $20 | | $— | | $20 | | Utility | | Other current liabilities | | $9 | | $— | | $9 | | Utility |
| |
| (a) | Represents the gross amounts of recognized assets/liabilities |
| |
| (b) | Represents the netting of fair value balances with the same counterparty |
| |
| (c) | Represents the net amounts of assets/liabilities presented on the Entergy Consolidated Balance Sheets |
| |
| (d) | Excludes cash collateral in the amount of $2 million posted as of December 31, 2016 and $9 million posted and $68 million held as of December 31, 2015 and $25 million held as of December 31, 2014, respectively2015. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effecteffects of Entergy’s derivative instruments designated as cash flow hedges on the consolidated statements of operations for the years ended December 31, 2016, 2015, 2014, and 20132014 are as follows:
| | Instrument | | Amount of gain (loss) recognized in other comprehensive income | | Income Statement location | | Amount of gain (loss) reclassified from AOCI into income (a) | | Amount of gain recognized in other comprehensive income | | Income Statement location | | Amount of gain (loss) reclassified from accumulated other comprehensive income into income (a) |
| | | | (In Millions) | | | | (In Millions) |
| 2016 | | | | | | | |
| Electricity swaps and options | | | $135 | | Competitive business operating revenues | | $293 |
| | | (In Millions) | | | | (In Millions) | | | | | | |
| 2015 | | | | | | | | | | | | |
| Electricity swaps and options | | $254 | | Competitive business operating revenues | | ($244) | | $254 | | Competitive business operating revenues | | ($244) |
| | | | | | | | | | | | | |
| 2014 | | | | | | | | | | | | |
| Electricity swaps and options | | $81 | | Competitive business operating revenues | | ($193) | | $81 | | Competitive business operating revenues | | ($193) |
| | | | | | | | |
| 2013 | | | | | | | |
| Electricity swaps and options | | ($190) | | Competitive business operating revenues | | $47 | |
| |
| (a) | Before taxes of $103 million, ($85) million, and ($68) million, and $18 million, for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively |
At each reporting period, Entergy measures its hedges for ineffectiveness. Any ineffectiveness is recognized in earnings during the period. The ineffective portion of cash flow hedges is recorded in competitive businesses operating revenues. The change in fair value of Entergy’s cash flow hedges due to ineffectiveness was ($356) thousand, $150 thousand, $7 million, and ($6)$7 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively.
Based on market prices as of December 31, 2015,2016, unrealized gains recorded in AOCI on cash flow hedges relating to power sales totaled ($167)9) million of net unrealized gains. Approximately ($154)15) million is expected to be reclassified from AOCI to operating revenues in the next twelve months. The actual amount reclassified from AOCI, however, could vary due to future changes in market prices.
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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effecteffects of Entergy’s derivative instruments not designated as hedging instruments on the consolidated statements of operations for the years ended December 31, 2016, 2015, and 2014 and 2013 isare as follows:
| |
Instrument | | Amount of gain (loss)
recognized in AOCI | | Income Statement
location | | Amount of gain (loss)
recorded in the income statement | | Amount of gain (loss) recognized in accumulated other comprehensive income | | Income Statement location | | Amount of gain (loss) recorded in the income statement |
| | | (In Millions) | | | | (In Millions) | | (In Millions) | | | | (In Millions) |
| 2016 | | | | | | | |
| Natural gas swaps | | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | $11 |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $125 |
| Electricity swaps and options | | | $— | (c) | Competitive business operating revenues | | ($11) |
| | | | | | | | |
| 2015 | | | | | | | | | | | | |
| Natural gas swaps | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($41) | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($41) |
| FTRs | | $— | | Purchased power expense | (b) | $166 | |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $166 |
| Electricity swaps and options | | $12 | | Competitive business operating revenues | | ($19) | | $12 | (c) | Competitive business operating revenues | | ($19) |
| | | | | | | | | | | | | |
| 2014 | | | | | | | | | | | | |
| Natural gas swaps | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($8) | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | ($8) |
| FTRs | | $— | | Purchased power expense | (b) | $229 | |
| Financial transmission rights | | | $— | | Purchased power expense | (b) | $229 |
| Electricity swaps and options | | ($13) | | Competitive business operating revenues | | $56 | | ($13) | (c) | Competitive business operating revenues | | $56 |
| | | | | | | | |
| 2013 | | | | | | | |
| Natural gas swaps | | $— | | Fuel, fuel-related expenses, and gas purchased for resale | (a) | $13 | |
| FTRs | | $— | | Purchased power expense | (b) | $3 | |
| Electricity swaps and options | | $1 | | Competitive business operating revenues | | ($50) | |
| |
| (a) | 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 asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (b) | Due to regulatory treatment, the changes in the estimated fair value of FTRsfinancial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the FTRsfinancial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (c) | Amount of gain (loss) recognized in accumulated other comprehensive income from electricity swaps and options de-designated as hedged items. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair values of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their balance sheets as of December 31, 20152016 and 20142015 are as follows:
|
| | | | | | |
| Instrument | | Balance Sheet Location | | Fair Value (a) | | Registrant |
| | | | | (In Millions) | | |
| 2016 | | | | | | |
| Assets: | | | | | | |
| Natural gas swaps | | Prepayments and other | | $10.9 | | Entergy Louisiana |
| Natural gas swaps | | Prepayments and other | | $2.3 | | Entergy Mississippi |
| Natural gas swaps | | Prepayments and other | | $0.2 | | Entergy New Orleans |
| | | | | | |
| Financial transmission rights | | Prepayments and other | | $5.4 | | Entergy Arkansas |
| Financial transmission rights | | Prepayments and other | | $8.5 | | Entergy Louisiana |
| Financial transmission rights | | Prepayments and other | | $3.2 | | Entergy Mississippi |
| Financial transmission rights | | Prepayments and other | | $1.1 | | Entergy New Orleans |
| Financial transmission rights | | Prepayments and other | | $3.1 | | Entergy Texas |
| | | | | | |
| 2015 | | | | | | |
| Assets: | | | | | | |
FTRsFinancial transmission rights | | Prepayments and other | | $7.9 | | Entergy Arkansas |
FTRsFinancial transmission rights | | Prepayments and other | | $8.5 | | Entergy Louisiana |
FTRsFinancial transmission rights | | Prepayments and other | | $2.4 | | Entergy Mississippi |
FTRsFinancial transmission rights | | Prepayments and other | | $1.5 | | Entergy New Orleans |
FTRsFinancial transmission rights | | Prepayments and other | | $2.2 | | Entergy Texas |
| | | | | | | |
| Liabilities: | | | | | | |
| Natural gas swaps | | Other current liabilities | | $7.0 | | Entergy Louisiana |
| Natural gas swaps | | Other current liabilities | | $1.3 | | Entergy Mississippi |
| Natural gas swaps | | Other current liabilities | | $0.5 | | Entergy New Orleans |
| | | | | | |
2014 | | | | | | |
Assets: | | | | | | |
FTRs | | Prepayments and other | | $0.7 | | Entergy Arkansas |
FTRs | | Prepayments and other | | $25.5 | | Entergy Louisiana |
FTRs | | Prepayments and other | | $3.4 | | Entergy Mississippi |
FTRs | | Prepayments and other | | $4.1 | | Entergy New Orleans |
FTRs | | Prepayments and other | | $12.3 | | Entergy Texas |
| | | | | | |
Liabilities: | | | | | | |
Natural gas swaps | | Other current liabilities | | $15.8 | | Entergy Louisiana |
Natural gas swaps | | Other current liabilities | | $2.8 | | Entergy Mississippi |
Natural gas swaps | | Other current liabilities | | $0.9 | | Entergy New Orleans |
| |
| (a) | As of December 31, 2016, letters of credit posted with MISO covered financial transmission right exposure of $0.3 million for Entergy Arkansas and $0.1 million for Entergy Mississippi. No cash collateral wasor letters of credit were required to be posted for financial transmission right exposure as of December 31, 2015 and 2014, respectively.2015. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The effects of the Registrant Subsidiaries’ derivative instruments not designated as hedging instruments on their income statements for the years ended December 31, 2016, 2015, 2014, and 20132014 are as follows:
|
| | | | | | |
Instrument | | Income Statement Location | | Amount of gain (loss) recorded in the income statement | | Registrant |
| | | | | (In Millions) | | |
| 2016 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $8.4 | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $3.1 | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($0.4) | (a) | Entergy New Orleans |
| | | | | | |
| Financial transmission rights | | Purchased power | | $23.2 | (b) | Entergy Arkansas |
| Financial transmission rights | | Purchased power | | $69.7 | (b) | Entergy Louisiana |
| Financial transmission rights | | Purchased power | | $16.6 | (b) | Entergy Mississippi |
| Financial transmission rights | | Purchased power | | $4.1 | (b) | Entergy New Orleans |
| Financial transmission rights | | Purchased power | | $10.2 | (b) | Entergy Texas |
| | | | | | |
| 2015 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($33.2) | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($6.1) | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($1.4) | (a) | Entergy New Orleans |
| | | | | | | |
FTRsFinancial transmission rights | | Purchased power | | $68.7 | (b) | Entergy Arkansas |
FTRsFinancial transmission rights | | Purchased power | | $55.4 | (b) | Entergy Louisiana |
FTRsFinancial transmission rights | | Purchased power | | $16.5 | (b) | Entergy Mississippi |
FTRsFinancial transmission rights | | Purchased power | | $8.5 | (b) | Entergy New Orleans |
FTRsFinancial transmission rights | | Purchased power | | $16.8 | (b) | Entergy Texas |
| | | | | | | |
| 2014 | | | | | | |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($5.5) | (a) | Entergy Louisiana |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($2.5) | (a) | Entergy Mississippi |
| Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | ($0.2) | (a) | Entergy New Orleans |
| | | | | | | |
FTRsFinancial transmission rights | | Purchased power | | $21.6 | (b) | Entergy Arkansas |
FTRsFinancial transmission rights | | Purchased power | | $103.5 | (b) | Entergy Louisiana |
FTRsFinancial transmission rights | | Purchased power | | $19.0 | (b) | Entergy Mississippi |
FTRsFinancial transmission rights | | Purchased power | | $16.5 | (b) | Entergy New Orleans |
FTRsFinancial transmission rights | | Purchased power | | $65.8 | | Entergy Texas |
| | | | | | |
2013 | | | | | | |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $10.5 | | Entergy Louisiana |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $2.5 | | Entergy Mississippi |
Natural gas swaps | | Fuel, fuel-related expenses, and gas purchased for resale | | $0.1 | | Entergy New Orleans |
| | | | | | |
FTRs | | Purchased power | | ($0.1) | | Entergy Arkansas |
FTRs | | Purchased power | | $0.5 | | Entergy Louisiana |
FTRs | | Purchased power | | $1.0 | | Entergy Mississippi |
FTRs | | Purchased power | | $1.2 | | Entergy New Orleans |
FTRs | | Purchased power | | $0.8 | (b) | Entergy Texas |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | 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 asset or liability. The gains or losses recorded as fuel expenses when the swaps are settled are recovered or refunded through fuel cost recovery mechanisms. |
| |
| (b) | Due to regulatory treatment, the changes in the estimated fair value of financial transmission rights for the Utility operating companies are recorded through purchased power expense and then such amounts are simultaneously reversed and recorded as an offsetting regulatory asset or liability. The gains or losses recorded as purchased power expense when the financial transmission rights for the Utility operating companies are settled are recovered or refunded through fuel cost recovery mechanisms. |
Fair Values
The estimated fair values of Entergy’s financial instruments and derivatives are determined using historical prices, bid prices, market quotes, and 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 the Entergy Wholesale Commodities business are reflected in future rates and therefore do not affect net income. 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.
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.
Effective first quarter 2016, Entergy retrospectively adopted ASU 2015-07, which simplifies the disclosure for fair value investments by removing the requirement to categorize within the fair value hierarchy investments for which fair value is measured using the net asset value per share as a practical expedient. For all periods presented the common trust funds have not been assigned a level and are presented within the fair value tables only as a reconciling item to the total fair value of investments.
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. Cash equivalents includes all unrestricted highly liquid debt instruments with an original or remaining maturity of three months or less at the date of purchase.
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
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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-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.instruments.
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’s best estimate of fair value for the asset or liability. Level 3 consists primarily of FTRs and derivative power contracts used as cash flow hedges of power sales at merchant power plants.
The values for power contract assets or liabilities are based on both observable inputs including public market prices and interest rates, and unobservable inputs such as implied volatilities, unit contingent discounts, expected basis differences, and credit adjusted counterparty interest rates. They are classified as Level 3 assets and liabilities. The
Entergy Corporation and Subsidiaries
Notes to Financial Statements
valuations of these assets and liabilities are performed by the Entergy Wholesale CommoditiesBusiness Unit Risk Control group and the Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group. The primary functions of the Entergy Wholesale CommoditiesBusiness Unit Risk Control group include: gathering, validating and reporting market data, providing market risk analyses and valuations in support of Entergy Wholesale Commodities’ commercial transactions, developing and administering protocols for the management of market risks, and implementing and maintaining controls around changes to market data in the energy trading and risk management system. The Business Unit Risk Control group is also responsible for managing the energy trading and risk management system, forecasting revenues, forward positions and analysis. The Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group performs functions related to market and counterparty settlements, revenue reporting and analysis and financial accounting. The Entergy Wholesale CommoditiesBusiness Unit Risk Control group reports to the Vice President and Treasurer while the Accounting Policy and Entergy Wholesale Commodities Accounting Policy and External Reporting group reports to the Chief Accounting Officer.
The amounts reflected as the fair value of electricity 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 to 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 the 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 quoted forward power market prices. The differences 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’ credit adjusted risk free rate are recorded as derivative contract assets or liabilities. For 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 electricity 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 U.S. 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.
On a daily basis, Entergy Wholesale Commoditiesthe Business Unit Risk Control group calculates the mark-to-market for electricity swaps and options. Entergy Wholesale CommoditiesThe Business Unit Risk Control group also validates forward market prices by comparing them to other sources of forward market prices or to settlement prices of actual market transactions. Significant differences are
Entergy Corporation and Subsidiaries
Notes to Financial Statements
analyzed and potentially adjusted based on these other sources of forward market prices or settlement prices of actual market transactions. Implied volatilities used to value options are also validated using actual counterparty quotes for Entergy Wholesale Commodities transactions when available, and uses multiple sources of market implied volatilities. 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 and liquidity effects are calculated for this analysis. This analysis is communicated to senior management within Entergy and Entergy Wholesale Commodities.
The values of FTRs are based on unobservable inputs, including estimates of congestion costs in MISO between applicable generation and load pricing nodes based on the 50th percentile of historical prices. They are classified as Level 3 assets and liabilities. The valuations of these assets and liabilities are performed by the Entergy Wholesale CommoditiesBusiness Unit Risk Control group for the unregulated business and by the System Planning and Operations Risk Control group for the Utility operating companies.group. The values are calculated internally and verified against the data published by MISO. Entergy’s Accounting Policy and Entergy Wholesale Commodities Accounting group reviews these valuations for reasonableness, with the assistance of others within the organization with knowledge of the various inputs and assumptions used in the valuation. The Business Unit Risk
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Control groups report to the Vice President and Treasurer. The Accounting Policy and Entergy Wholesale Commodities Accounting group reports to the Chief Accounting Officer.
The following tables set forth, by level within the fair value hierarchy, Entergy’s assets and liabilities that are accounted for at fair value on a recurring basis as of December 31, 20152016 and December 31, 2014.2015. 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.
| | | 2015 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $1,287 |
| |
| $— |
| |
| $— |
| |
| $1,287 |
| |
| $1,058 |
| |
| $— |
| |
| $— |
| |
| $1,058 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 468 |
| | 2,727 |
| | — |
| | 3,195 |
| | 480 |
| | — |
| | — |
| | 480 |
|
| Debt securities | | 1,061 |
| | 1,094 |
| | — |
| | 2,155 |
| | 985 |
| | 1,228 |
| | — |
| | 2,213 |
|
| Common trusts (b) | | | | | | | | | 3,031 |
|
| Power contracts | | — |
| | — |
| | 195 |
| | 195 |
| | — |
| | — |
| | 16 |
| | 16 |
|
| Securitization recovery trust account | | 50 |
| | — |
| | — |
| | 50 |
| | 46 |
| | — |
| | — |
| | 46 |
|
| Escrow accounts | | 425 |
| | — |
| | — |
| | 425 |
| | 433 |
| | — |
| | — |
| | 433 |
|
| FTRs | | — |
| | — |
| | 23 |
| | 23 |
| |
| Gas hedge contracts | | | 13 |
| | — |
| | — |
| | 13 |
|
| Financial transmission rights | | | — |
| | — |
| | 21 |
| | 21 |
|
| | |
| $3,291 |
| |
| $3,821 |
| |
| $218 |
| |
| $7,330 |
| |
| $3,015 |
| |
| $1,228 |
| |
| $37 |
| |
| $7,311 |
|
| Liabilities: | | | | | | | | | | | | | | | | |
| Power contracts | |
| $— |
| |
| $— |
| |
| $6 |
| |
| $6 |
| |
| $— |
| |
| $— |
| |
| $11 |
| |
| $11 |
|
| Gas hedge contracts | | 9 |
| | — |
| | — |
| | 9 |
| |
| | |
| $9 |
| |
| $— |
| |
| $6 |
| |
| $15 |
| |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2015 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $1,291 |
| |
| $— |
| |
| $— |
| |
| $1,291 |
| |
| $1,287 |
| |
| $— |
| |
| $— |
| |
| $1,287 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 452 |
| | 2,834 |
| | — |
| | 3,286 |
| | 468 |
| | — |
| | — |
| | 468 |
|
| Debt securities | | 880 |
| | 1,205 |
| | — |
| | 2,085 |
| | 1,061 |
| | 1,094 |
| | — |
| | 2,155 |
|
| Common trusts (b) | | | | | | | | | 2,727 |
|
| Power contracts | | — |
| | — |
| | 217 |
| | 217 |
| | — |
| | — |
| | 195 |
| | 195 |
|
| Securitization recovery trust account | | 44 |
| | — |
| | — |
| | 44 |
| | 50 |
| | — |
| | — |
| | 50 |
|
| Escrow accounts | | 362 |
| | — |
| | — |
| | 362 |
| | 425 |
| | — |
| | — |
| | 425 |
|
| FTRs | | — |
| | — |
| | 47 |
| | 47 |
| |
| Financial transmission rights | | | — |
| | — |
| | 23 |
| | 23 |
|
| | |
| $3,029 |
| |
| $4,039 |
| |
| $264 |
| |
| $7,332 |
| |
| $3,291 |
| |
| $1,094 |
| |
| $218 |
| |
| $7,330 |
|
| Liabilities: | | | | | | | | | | | | | | | | |
| Power contracts | |
| $— |
| |
| $— |
| |
| $2 |
| |
| $2 |
| |
| $— |
| |
| $— |
| |
| $6 |
| |
| $6 |
|
| Gas hedge contracts | | 20 |
| | — |
| | — |
| | 20 |
| | 9 |
| | — |
| | — |
| | 9 |
|
| | |
| $20 |
| |
| $— |
| |
| $2 |
| |
| $22 |
| |
| $9 |
| |
| $— |
| |
| $6 |
| |
| $15 |
|
| |
| (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 1716 to the financial statements for additional information on the investment portfolios. |
| |
| (b) | Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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, 2016, 2015, 2014, and 2013:2014:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | Power Contracts | FTRs | | Power Contracts | FTRs | | Power Contracts | FTRs | Power Contracts | Financial transmission rights | | Power Contracts | Financial transmission rights | | Power Contracts | Financial transmission rights |
| | (In Millions) | (In Millions) |
| Balance as of January 1, |
| $215 |
|
| $47 |
| |
| ($133 | ) |
| $34 |
| |
| $178 |
|
| $— |
|
| $189 |
|
| $23 |
| |
| $215 |
|
| $47 |
| |
| ($133 | ) |
| $34 |
|
| Total gains (losses) for the period (a) | | | | | | | | | | |
| Included in earnings | (20 | ) | (1 | ) | | 55 |
| 2 |
| | (73 | ) | — |
| (10 | ) | — |
| | (20 | ) | (1 | ) | | 55 |
| 2 |
|
| Included in OCI | 254 |
| — |
| | 131 |
| — |
| | (204 | ) | — |
| 135 |
| — |
| | 254 |
| — |
| | 131 |
| — |
|
| Included as a regulatory liability/asset | — |
| 63 |
| | — |
| 119 |
| | — |
| — |
| — |
| 68 |
| | — |
| 63 |
| | — |
| 119 |
|
| Issuances of FTRs | — |
| 80 |
| | — |
| 121 |
| | — |
| 37 |
| |
| Issuances of financial transmission rights | | — |
| 55 |
| | — |
| 80 |
| | — |
| 121 |
|
| Purchases | 15 |
| — |
| | 17 |
| — |
| | 14 |
| — |
| — |
| — |
| | 15 |
| — |
| | 17 |
| — |
|
| Settlements | (275 | ) | (166 | ) | | 145 |
| (229 | ) | | (48 | ) | (3 | ) | (309 | ) | (125 | ) | | (275 | ) | (166 | ) | | 145 |
| (229 | ) |
| Balance as of December 31, |
| $189 |
|
| $23 |
| |
| $215 |
|
| $47 |
| |
| ($133 | ) |
| $34 |
|
| $5 |
|
| $21 |
| |
| $189 |
|
| $23 |
| |
| $215 |
|
| $47 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
| (a) | Change in unrealized gains or losses for the period included in earnings for derivatives held at the end of the reporting period is $0.2 million, $3 million, $120 million, and ($35)$120 million for the years ended December 31, 2016, 2015, 2014, and 2013,2014, respectively. |
The following table sets forth a description of the types of transactions classified as Level 3 in the fair value hierarchy and significant unobservable inputs to each which cause that classification, as of December 31, 2015:2016:
|
| | | | | | | | |
| Transaction Type | | Fair Value as of December 31, 2015 | | Significant Unobservable Inputs | | Range from Average % | | Effect on Fair Value |
| | | (In Millions) | | | | | | (In Millions) |
| Power contracts - electricity swaps | | $157 | | Unit contingent discount | | +/-3% | | $8 |
| Power contracts - electricity options | | $32 | | Implied volatility | | +/-83% | | $12 |
|
| | | | | | | | |
| Transaction Type | | Fair Value as of December 31, 2016 | | Significant Unobservable Inputs | | Range from Average % | | Effect on Fair Value |
| | (In Millions) | | | | | | (In Millions) |
| Power contracts - electricity swaps | | $5 | | Unit contingent discount | | +/-4% | | $— |
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’ assets that are accounted for at fair value on a recurring basis as of December 31, 20152016 and December 31, 2014.2015. 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 Arkansas
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | |
| $3.6 |
| |
| $— |
| |
| $— |
| |
| $3.6 |
|
| Debt securities | | 112.5 |
| | 196.8 |
| | — |
| | 309.3 |
|
| Common trusts (b) | | | | | | | | 521.8 |
|
| Securitization recovery trust account | | 4.1 |
| | — |
| | — |
| | 4.1 |
|
| Escrow accounts | | 7.1 |
| | — |
| | — |
| | 7.1 |
|
| Financial transmission rights | | — |
| | — |
| | 5.4 |
| | 5.4 |
|
| | |
| $127.3 |
| |
| $196.8 |
| |
| $5.4 |
| |
| $851.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | |
| $3.0 |
| |
| $— |
| |
| $— |
| |
| $3.0 |
|
| Debt securities | | 110.5 |
| | 193.4 |
| | — |
| | 303.9 |
|
| Common trusts (b) | | | | | | | | 464.4 |
|
| Securitization recovery trust account | | 4.2 |
| | — |
| | — |
| | 4.2 |
|
| Escrow accounts | | 12.2 |
| | — |
| | — |
| | 12.2 |
|
| Financial transmission rights | | — |
| | — |
| | 7.9 |
| | 7.9 |
|
| | |
| $129.9 |
| |
| $193.4 |
| |
| $7.9 |
| |
| $795.6 |
|
Entergy Louisiana
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $163.9 |
| |
| $— |
| |
| $— |
| |
| $163.9 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 13.9 |
| | — |
| | — |
| | 13.9 |
|
| Debt securities | | 132.3 |
| | 292.5 |
| | — |
| | 424.8 |
|
| Common trusts (b) | | | | | | | | 702.0 |
|
| Escrow accounts | | 305.7 |
| | — |
| | — |
| | 305.7 |
|
| Securitization recovery trust account | | 2.8 |
| | — |
| | — |
| | 2.8 |
|
| Gas hedge contracts | | 10.9 |
| | — |
| | — |
| | 10.9 |
|
| Financial transmission rights | | — |
| | — |
| | 8.5 |
| | 8.5 |
|
| | |
| $629.5 |
| |
| $292.5 |
| |
| $8.5 |
| |
| $1,632.5 |
|
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $34.8 |
| |
| $— |
| |
| $— |
| |
| $34.8 |
|
| Decommissioning trust funds (a): | | |
| | |
| | |
| | |
|
| Equity securities | | 7.1 |
| | — |
| | — |
| | 7.1 |
|
| Debt securities | | 161.1 |
| | 248.8 |
| | — |
| | 409.9 |
|
| Common trusts (b) | | | | | | | | 625.3 |
|
| Escrow accounts | | 290.4 |
| | — |
| | — |
| | 290.4 |
|
| Securitization recovery trust account | | 3.2 |
| | — |
| | — |
| | 3.2 |
|
| Financial transmission rights | | — |
| | — |
| | 8.5 |
| | 8.5 |
|
| | |
| $496.6 |
| |
| $248.8 |
| |
| $8.5 |
| |
| $1,379.2 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $7.0 |
| |
| $— |
| |
| $— |
| |
| $7.0 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy ArkansasMississippi
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | |
| $3.0 |
| |
| $464.4 |
| |
| $— |
| |
| $467.4 |
|
| Debt securities | | 110.5 |
| | 193.4 |
| | — |
| | 303.9 |
|
| Securitization recovery trust account | | 4.2 |
| | — |
| | — |
| | 4.2 |
|
| Escrow accounts | | 12.2 |
| | — |
| | — |
| | 12.2 |
|
| FTRs | | — |
| | — |
| | 7.9 |
| | 7.9 |
|
| | |
| $129.9 |
| |
| $657.8 |
| |
| $7.9 |
| |
| $795.6 |
|
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $76.8 |
| |
| $— |
| |
| $— |
| |
| $76.8 |
|
| Escrow accounts | | 31.8 |
| | — |
| | — |
| | 31.8 |
|
| Gas hedge contracts | | 2.3 |
| | — |
| | — |
| | 2.3 |
|
| Financial transmission rights | | — |
| | — |
| | 3.2 |
| | 3.2 |
|
| | |
| $110.9 |
| |
| $— |
| |
| $3.2 |
| |
| $114.1 |
|
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $208.0 |
| |
| $— |
| |
| $— |
| |
| $208.0 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 7.2 |
| | 480.1 |
| | — |
| | 487.3 |
|
| Debt securities | | 72.2 |
| | 210.4 |
| | — |
| | 282.6 |
|
| Securitization recovery trust account | | 4.1 |
| | — |
| | — |
| | 4.1 |
|
| Escrow accounts | | 12.2 |
| | — |
| | — |
| | 12.2 |
|
| FTRs | | — |
| | — |
| | 0.7 |
| | 0.7 |
|
| | |
| $303.7 |
| |
| $690.5 |
| |
| $0.7 |
| |
| $994.9 |
|
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $144.2 |
| |
| $— |
| |
| $— |
| |
| $144.2 |
|
| Escrow accounts | | 41.7 |
| | — |
| | — |
| | 41.7 |
|
| Financial transmission rights | | — |
| | — |
| | 2.4 |
| | 2.4 |
|
| | |
| $185.9 |
| |
| $— |
| |
| $2.4 |
| |
| $188.3 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $1.3 |
| |
| $— |
| |
| $— |
| |
| $1.3 |
|
Entergy LouisianaNew Orleans
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $34.8 |
| |
| $— |
| |
| $— |
| |
| $34.8 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 7.1 |
| | 625.3 |
| | — |
| | 632.4 |
|
| Debt securities | | 161.1 |
| | 248.8 |
| | — |
| | 409.9 |
|
| Securitization recovery trust account | | 3.2 |
| | — |
| | — |
| | 3.2 |
|
| Escrow accounts | | 290.4 |
| | — |
| | — |
| | 290.4 |
|
| FTRs | | — |
| | — |
| | 8.5 |
| | 8.5 |
|
| | |
| $496.6 |
| |
| $874.1 |
| |
| $8.5 |
| |
| $1,379.2 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $7.0 |
| |
| $— |
| |
| $— |
| |
| $7.0 |
|
|
| | | | | | | | | | | | | | | | |
| 2016 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $103.0 |
| |
| $— |
| |
| $— |
| |
| $103.0 |
|
| Securitization recovery trust account | | 1.7 |
| | — |
| | — |
| | 1.7 |
|
| Escrow accounts | | 88.6 |
| | — |
| | — |
| | 88.6 |
|
| Gas hedge contracts | | 0.2 |
| | — |
| | — |
| | 0.2 |
|
| Financial transmission rights | | — |
| | — |
| | 1.1 |
| | 1.1 |
|
| | |
| $193.5 |
| |
| $— |
| |
| $1.1 |
| |
| $194.6 |
|
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $87.8 |
| |
| $— |
| |
| $— |
| |
| $87.8 |
|
| Securitization recovery trust account | | 4.6 |
| | — |
| | — |
| | 4.6 |
|
| Escrow accounts | | 81.0 |
| | — |
| | — |
| | 81.0 |
|
| Financial transmission rights | | — |
| | — |
| | 1.5 |
| | 1.5 |
|
| | |
| $173.4 |
| |
| $— |
| |
| $1.5 |
| |
| $174.9 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $0.5 |
| |
| $— |
| |
| $— |
| |
| $0.5 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | �� | | |
| Temporary cash investments | |
| $266.7 |
| |
| $— |
| |
| $— |
| |
| $266.7 |
|
| Decommissioning trust funds (a): | | | | | | | | |
| Equity securities | | 15.3 |
| | 620.2 |
| | — |
| | 635.5 |
|
| Debt securities | | 150.6 |
| | 235.2 |
| | — |
| | 385.8 |
|
| Securitization recovery trust account | | 3.1 |
| | — |
| | — |
| | 3.1 |
|
| Escrow accounts | | 290.1 |
| | — |
| | — |
| | 290.1 |
|
| FTRs | | — |
| | — |
| | 25.5 |
| | 25.5 |
|
| | |
| $725.8 |
| |
| $855.4 |
| |
| $25.5 |
| |
| $1,606.7 |
|
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $15.8 |
| |
| $— |
| |
| $— |
| |
| $15.8 |
|
Entergy Mississippi
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $144.2 |
| |
| $— |
| |
| $— |
| |
| $144.2 |
|
| Escrow accounts | | 41.7 |
| | — |
| | — |
| | 41.7 |
|
| FTRs | | — |
| | — |
| | 2.4 |
| | 2.4 |
|
| | |
| $185.9 |
| |
| $— |
| |
| $2.4 |
| |
| $188.3 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $1.3 |
| |
| $— |
| |
| $— |
| |
| $1.3 |
|
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $60.4 |
| |
| $— |
| |
| $— |
| |
| $60.4 |
|
| Escrow accounts | | 41.8 |
| | — |
| | — |
| | 41.8 |
|
| FTRs | | — |
| | — |
| | 3.4 |
| | 3.4 |
|
| | |
| $102.2 |
| |
| $— |
| |
| $3.4 |
| |
| $105.6 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $2.8 |
| |
| $— |
| |
| $— |
| |
| $2.8 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $87.8 |
| |
| $— |
| |
| $— |
| |
| $87.8 |
|
| Securitization recovery trust account | | 4.6 |
| | — |
| | — |
| | 4.6 |
|
| Escrow accounts | | 81.0 |
| | — |
| | — |
| | 81.0 |
|
| FTRs | | — |
| | — |
| | 1.5 |
| | 1.5 |
|
| | |
| $173.4 |
| |
| $— |
| |
| $1.5 |
| |
| $174.9 |
|
| | | | | | | | | |
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $0.5 |
| |
| $— |
| |
| $— |
| |
| $0.5 |
|
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
| Assets: | | | | | | | | |
| Temporary cash investments | |
| $41.4 |
| |
| $— |
| |
| $— |
| |
| $41.4 |
|
| Escrow accounts | | 18.0 |
| | — |
| | — |
| | 18.0 |
|
| FTRs | | — |
| | — |
| | 4.1 |
| | 4.1 |
|
| | |
| $59.4 |
| |
| $— |
| |
| $4.1 |
| |
| $63.5 |
|
| Liabilities: | | | | | | | | |
| Gas hedge contracts | |
| $0.9 |
| |
| $— |
| |
| $— |
| |
| $0.9 |
|
Entergy Texas
| | | 2015 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | | |
| $5.0 |
| |
| $— |
| |
| $— |
| |
| $5.0 |
|
| Securitization recovery trust account | |
| $38.2 |
| |
| $— |
| |
| $— |
| |
| $38.2 |
| | 37.5 |
| | — |
| | — |
| | 37.5 |
|
| FTRs | | — |
| | — |
| | 2.2 |
| | 2.2 |
| |
| Financial transmission rights | | | — |
| | — |
| | 3.1 |
| | 3.1 |
|
| | |
| $38.2 |
| |
| $— |
| |
| $2.2 |
| |
| $40.4 |
| |
| $42.5 |
| |
| $— |
| |
| $3.1 |
| |
| $45.6 |
|
|
| | | | | | | | | | | | | | | | |
| 2014 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Temporary cash investments | |
| $28.7 |
| |
| $— |
| |
| $— |
| |
| $28.7 |
|
| Securitization recovery trust account | | 37.2 |
| | — |
| | — |
| | 37.2 |
|
| FTRs | | — |
| | — |
| | 12.3 |
| | 12.3 |
|
| | |
| $65.9 |
| |
| $— |
| |
| $12.3 |
| |
| $78.2 |
|
|
| | | | | | | | | | | | | | | | |
| 2015 | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) |
Assets: | | | | | | | | |
| Securitization recovery trust account | |
| $38.2 |
| |
| $— |
| |
| $— |
| |
| $38.2 |
|
| Financial transmission rights | | — |
| | — |
| | 2.2 |
| | 2.2 |
|
| | |
| $38.2 |
| |
| $— |
| |
| $2.2 |
| |
| $40.4 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
System Energy
| | | 2015 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2016 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $222.0 |
| |
| $— |
| |
| $— |
| |
| $222.0 |
| |
| $245.1 |
| |
| $— |
| |
| $— |
| |
| $245.1 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 1.8 |
| | 421.9 |
| | — |
| | 423.7 |
| | 0.3 |
| | — |
| | — |
| | 0.3 |
|
| Debt securities | | 218.6 |
| | 59.2 |
| | — |
| | 277.8 |
| | 248.3 |
| | 58.3 |
| | — |
| | 306.6 |
|
| Common trusts (b) | | | | | | | | | 473.6 |
|
| | |
| $442.4 |
| |
| $481.1 |
| |
| $— |
| |
| $923.5 |
| |
| $493.7 |
| |
| $58.3 |
| |
| $— |
| |
| $1,025.6 |
|
| | | 2014 | | Level 1 | | Level 2 | | Level 3 | | Total | |
| 2015 | | | Level 1 | | Level 2 | | Level 3 | | Total |
| | | (In Millions) | | (In Millions) |
| Assets: | | | | | | | | | | | | | | | | |
| Temporary cash investments | |
| $222.4 |
| |
| $— |
| |
| $— |
| |
| $222.4 |
| |
| $222.0 |
| |
| $— |
| |
| $— |
| |
| $222.0 |
|
| Decommissioning trust funds (a): | | | | | | | | | | | | | | | | |
| Equity securities | | 2.0 |
| | 422.5 |
| | — |
| | 424.5 |
| | 1.8 |
| | — |
| | — |
| | 1.8 |
|
| Debt securities | | 194.2 |
| | 61.1 |
| | — |
| | 255.3 |
| | 218.6 |
| | 59.2 |
| | — |
| | 277.8 |
|
| Common trusts (b) | | | | | | | | | 421.9 |
|
| | |
| $418.6 |
| |
| $483.6 |
| |
| $— |
| |
| $902.2 |
| |
| $442.4 |
| |
| $59.2 |
| |
| $— |
| |
| $923.5 |
|
| |
| (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 1716 to the financial statements for additional information on the investment portfolios. |
| |
| (b) | Common trust funds are not publicly quoted, and are valued by the fund administrators using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value table. The fund administrator of these investments allows daily trading at the net asset value and trades settle at a later date. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 year ended December 31, 2016.
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana |
| Entergy Mississippi |
| Entergy New Orleans |
| Entergy Texas |
| | (In Millions) |
| | |
|
|
|
|
|
|
|
|
|
|
|
| Balance as of January 1, |
| $7.9 |
| |
| $8.5 |
| |
| $2.4 |
| |
| $1.5 |
| |
| $2.2 |
|
| Issuances of financial transmission rights | 18.8 |
| | 18.1 |
| | 5.9 |
| | 2.8 |
| | 9.3 |
|
| Gains (losses) included as a regulatory liability/asset | 1.9 |
| | 51.6 |
| | 11.5 |
| | 0.9 |
| | 1.8 |
|
| Settlements | (23.2 | ) | | (69.7 | ) | | (16.6 | ) | | (4.1 | ) | | (10.2 | ) |
| Balance as of December 31, |
| $5.4 |
| |
| $8.5 |
| |
| $3.2 |
| |
| $1.1 |
| |
| $3.1 |
|
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 year ended December 31, 2015.
|
| | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas | | Entergy Louisiana |
| Entergy Mississippi |
| Entergy New Orleans |
| Entergy Texas |
| | (In Millions) |
| | |
|
|
|
|
|
|
|
|
|
|
|
| Balance as of January 1, |
| $0.7 |
| |
| $25.5 |
| |
| $3.4 |
| |
| $4.1 |
| |
| $12.3 |
|
| Issuances of FTRs | 7.0 |
| | 48.3 |
| | 5.4 |
| | 7.3 |
| | 11.4 |
|
| Gains (losses) included as a regulatory liability/asset | 68.9 |
| | (9.9 | ) | | 10.1 |
| | (1.4 | ) | | (4.7 | ) |
| Settlements | (68.7 | ) | | (55.4 | ) | | (16.5 | ) | | (8.5 | ) | | (16.8 | ) |
| Balance as of December 31, |
| $7.9 |
| |
| $8.5 |
| |
| $2.4 |
| |
| $1.5 |
| |
| $2.2 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 year ended December 31, 2014.
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas |
| | (In Millions) | (In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Balance as of January 1, |
| $— |
| |
| $12.4 |
| |
| $1.0 |
| |
| $2.0 |
| |
| $18.4 |
|
| $0.7 |
| |
| $25.5 |
| |
| $3.4 |
| |
| $4.1 |
| |
| $12.3 |
|
| Issuances of FTRs | 4.2 |
| | 58.8 |
| | 15.2 |
| | 8.3 |
| | 33.2 |
| |
| Issuances of financial transmission rights | | 7.0 |
| | 48.3 |
| | 5.4 |
| | 7.3 |
| | 11.4 |
|
| Gains (losses) included as a regulatory liability/asset | 18.1 |
| | 57.8 |
| | 6.2 |
| | 10.3 |
| | 26.5 |
| 68.9 |
| | (9.9 | ) | | 10.1 |
| | (1.4 | ) | | (4.7 | ) |
| Settlements | (21.6 | ) | | (103.5 | ) | | (19.0 | ) | | (16.5 | ) | | (65.8 | ) | (68.7 | ) | | (55.4 | ) | | (16.5 | ) | | (8.5 | ) | | (16.8 | ) |
| Balance as of December 31, |
| $0.7 |
| |
| $25.5 |
| |
| $3.4 |
| |
| $4.1 |
| |
| $12.3 |
|
| $7.9 |
| |
| $8.5 |
| |
| $2.4 |
| |
| $1.5 |
| |
| $2.2 |
|
NOTE 17.16. DECOMMISSIONING TRUST FUNDS (Entergy Corporation, Entergy Arkansas, 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, andIndian Point 2, Vermont Yankee, and Palisades (NYPA currently retains the decommissioning trusts and liabilities for Indian Point 3 and FitzPatrick).Palisades. The funds are invested primarily in equity securities, fixed-rate debt securities, and cash and cash equivalents.
For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning trust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specified their decommissioning obligations. At the time of the acquisition of the plants Entergy recorded a contract asset that represented an estimate of the present value of the difference between the stipulated contract amount for decommissioning the plants less the decommissioning costs estimated in independent decommissioning cost studies.
In August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants to Entergy. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. As a result of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
agreement with NYPA, in the third quarter 2016, Entergy removed the contract asset from its balance sheet, and recorded receivables for the beneficial interests in the decommissioning trust funds and recorded asset retirement obligations for the decommissioning liabilities. At December 31, 2016, the fair values of the decommissioning trust funds held by NYPA were $719 million for the Indian Point 3 plant and $785 million for the FitzPatrick plant. The fair values are based on the trust statements received from NYPA and are valued by the fund administrator using net asset value as a practical expedient. Accordingly, these funds are not assigned a level in the fair value hierarchy. For Indian Point 3, the receivable for the beneficial interest in the decommissioning trust fund is recorded in other deferred debits on the consolidated balance sheet. For FitzPatrick, the receivable for the beneficial interest in the decommissioning trust fund is classified as held for sale within other deferred debits on the consolidated balance sheet. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. See Note 9 to the financial statements for further discussion of the decommissioning agreements with NYPA and see Note 14 to the financial statements for further discussion of the sale of FitzPatrick.
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 30% interest in River Bend formerly owned by Cajun, Entergy Louisiana has recorded an offsetting amount of unrealized gains/(losses) in other deferred credits. Decommissioning trust funds for Pilgrim, Indian Point 1, andIndian 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. Generally, Entergy records 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, 20152016 and 20142015 are summarized as follows:
|
| | | | | | | | | | | | |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2015 | | |
| | |
| | |
|
| Equity Securities | |
| $3,195 |
| |
| $1,396 |
| |
| $2 |
|
| Debt Securities | | 2,155 |
| | 41 |
| | 17 |
|
| Total | |
| $5,350 |
| |
| $1,437 |
| |
| $19 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements |
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2016 | | 2015 |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| Equity Securities | |
| $3,511 |
| |
| $1,673 |
| |
| $1 |
| |
| $3,195 |
| |
| $1,396 |
| |
| $2 |
|
| Debt Securities | | 2,213 |
| | 34 |
| | 27 |
| | 2,155 |
| | 41 |
| | 17 |
|
| Total | |
| $5,724 |
| |
| $1,707 |
| |
| $28 |
| |
| $5,350 |
| |
| $1,437 |
| |
| $19 |
|
|
| | | | | | | | | | | | |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2014 | | |
| | |
| | |
|
| Equity Securities | |
| $3,286 |
| |
| $1,513 |
| |
| $1 |
|
| Debt Securities | | 2,085 |
| | 76 |
| | 6 |
|
| Total | |
| $5,371 |
| |
| $1,589 |
| |
| $7 |
|
Deferred taxes on unrealized gains/(losses) are recorded in other comprehensive income (loss) 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 $342$399 million and $396$342 million as of December 31, 20152016 and 2014,2015, respectively. The amortized cost of debt securities was $2,212 million as of December 31, 2016 and $2,124 million as of December 31, 2015 and $2,019 million as of December 31, 2014.2015. As of December 31, 2015,2016, the debt securities have an average coupon rate of approximately 3.16%3.21%, an average duration of approximately 5.705.89 years, and an average maturity of approximately 8.559.39 years. The equity securities are generally held in funds that are designed to approximate or somewhat exceed the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
return of the Standard & Poor’s 500 Index. A relatively small percentage of the equity 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, 2016 and 2015:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $54 |
| |
| $2 |
| |
| $1,031 |
| |
| $15 |
|
| More than 12 months | 1 |
| | — |
| | 61 |
| | 2 |
|
| Total |
| $55 |
| |
| $2 |
| |
| $1,092 |
| |
| $17 |
|
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, 2014:
| | | | | | | | | | | | 2016 | | 2015 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $9 |
| |
| $1 |
| |
| $277 |
| |
| $2 |
|
| $23 |
| |
| $1 |
| |
| $1,169 |
| |
| $26 |
| |
| $54 |
| |
| $2 |
| |
| $1,031 |
| |
| $15 |
|
| More than 12 months | — |
| | — |
| | 163 |
| | 4 |
| 1 |
| | — |
| | 20 |
| | 1 |
| | 1 |
| | — |
| | 61 |
| | 2 |
|
| Total |
| $9 |
| |
| $1 |
| |
| $440 |
| |
| $6 |
|
| $24 |
| |
| $1 |
| |
| $1,189 |
| |
| $27 |
| |
| $55 |
| |
| $2 |
| |
| $1,092 |
| |
| $17 |
|
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, 2016 and 2015 are as follows:
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
| less than 1 year |
| $125 |
| |
| $77 |
|
| 1 year - 5 years | 763 |
| | 857 |
|
| 5 years - 10 years | 719 |
| | 704 |
|
| 10 years - 15 years | 109 |
| | 124 |
|
| 15 years - 20 years | 73 |
| | 50 |
|
| 20 years+ | 424 |
| | 343 |
|
| Total |
| $2,213 |
| |
| $2,155 |
|
During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $2,409 million, $2,492 million, and $1,872 million, respectively. During the years ended December 31, 2016, 2015, and 2014, gross gains of $32 million, $72 million, and $39 million, respectively, and gross losses of $13 million, $13 million, and $8 million, respectively, were reclassified out of other comprehensive income into earnings.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2015 and 2014 are as follows:
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
| less than 1 year |
| $77 |
| |
| $94 |
|
| 1 year - 5 years | 857 |
| | 783 |
|
| 5 years - 10 years | 704 |
| | 681 |
|
| 10 years - 15 years | 124 |
| | 173 |
|
| 15 years - 20 years | 50 |
| | 79 |
|
| 20 years+ | 343 |
| | 275 |
|
| Total |
| $2,155 |
| |
| $2,085 |
|
During the years ended December 31, 2015, 2014, and 2013, proceeds from the dispositions of securities amounted to $2,492 million, $1,872 million, and $2,032 million, respectively. During the years ended December 31, 2015, 2014, and 2013, gross gains of $72 million, $39 million, and $91 million, respectively, and gross losses of $13 million, $8 million, and $11 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, 20152016 and 20142015 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2016 | | 2015 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2015 | | | | | | | |
| | | | (In Millions) |
| Equity Securities | |
| $467.4 |
| |
| $234.4 |
| |
| $0.2 |
| |
| $525.4 |
| |
| $281.5 |
| |
| $— |
| |
| $467.4 |
| |
| $234.4 |
| |
| $0.2 |
|
| Debt Securities | | 303.9 |
| | 4.1 |
| | 2.2 |
| | 309.3 |
| | 3.4 |
| | 4.2 |
| | 303.9 |
| | 4.1 |
| | 2.2 |
|
| Total | |
| $771.3 |
| |
| $238.5 |
| |
| $2.4 |
| |
| $834.7 |
| |
| $284.9 |
| |
| $4.2 |
| |
| $771.3 |
| |
| $238.5 |
| |
| $2.4 |
|
| 2014 | | | | | | | |
| Equity Securities | |
| $487.3 |
| |
| $248.9 |
| |
| $— |
| |
| Debt Securities | | 282.6 |
| | 6.2 |
| | 1.1 |
| |
| Total | |
| $769.9 |
| |
| $255.1 |
| |
| $1.1 |
| |
The amortized cost of debt securities was $310.1 million as of December 31, 2016 and $301.8 million as of December 31, 2015 and $277.4 million as of December 31, 2014.2015. As of December 31, 2015,2016, the debt securities have an average coupon rate of approximately 2.44%2.65%, an average duration of approximately 5.145.37 years, and an average maturity of approximately 5.98 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 equity 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, 2015:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $7.8 |
| |
| $0.2 |
| |
| $111.4 |
| |
| $1.7 |
|
| More than 12 months | — |
| | — |
| | 18.5 |
| | 0.5 |
|
| Total |
| $7.8 |
| |
| $0.2 |
| |
| $129.9 |
| |
| $2.2 |
|
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, 2014:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $56.5 |
| |
| $0.3 |
|
| More than 12 months | — |
| | — |
| | 34.8 |
| | 0.8 |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $91.3 |
| |
| $1.1 |
|
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2015 and 2014 are as follows:
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
| less than 1 year |
| $1.8 |
| |
| $14.9 |
|
| 1 year - 5 years | 145.2 |
| | 127.3 |
|
| 5 years - 10 years | 138.5 |
| | 128.2 |
|
| 10 years - 15 years | 2.4 |
| | 1.7 |
|
| 15 years - 20 years | 2.0 |
| | 1.0 |
|
| 20 years+ | 14.0 |
| | 9.5 |
|
| Total |
| $303.9 |
| |
| $282.6 |
|
During the years ended December 31, 2015, 2014, and 2013, proceeds from the dispositions of securities amounted to $213 million, $181.5 million, and $266.4 million, respectively. During the years ended December 31, 2015, 2014, and 2013, gross gains of $5.9 million, $8.7 million, and $16.8 million, respectively, and gross losses of $0.3 million, $0.3 million, and $0.6 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, 2015 and 2014 are summarized as follows:
|
| | | | | | | | | | | | |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| 2015 | | | | | | |
| Equity Securities | |
| $632.4 |
| |
| $283.7 |
| |
| $0.2 |
|
| Debt Securities | | 409.9 |
| | 13.2 |
| | 2.4 |
|
| Total | |
| $1,042.3 |
| |
| $296.9 |
| |
| $2.6 |
|
| 2014 | | | | | | |
| Equity Securities | |
| $635.5 |
| |
| $294.3 |
| |
| $— |
|
| Debt Securities | | 385.8 |
| | 18.8 |
| | 0.7 |
|
| Total | |
| $1,021.3 |
| |
| $313.1 |
| |
| $0.7 |
|
The amortized cost of debt securities was $399.2 million as of December 31, 2015 and $369.4 million as of December 31, 2014. As of December 31, 2015, the debt securities have an average coupon rate of approximately 3.89%, an average duration of approximately 5.49 years, and an average maturity of approximately 9.916.31 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 equity 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, 2016 and 2015:
| | | | | | | | | | | | 2016 | | 2015 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $9.4 |
| |
| $0.2 |
| |
| $124.0 |
| |
| $2.0 |
|
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
| |
| $7.8 |
| |
| $0.2 |
| |
| $111.4 |
| |
| $1.7 |
|
| More than 12 months | — |
| | — |
| | 7.4 |
| | 0.4 |
| — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 18.5 |
| | 0.5 |
|
| Total |
| $9.4 |
| |
| $0.2 |
| |
| $131.4 |
| |
| $2.4 |
|
| $— |
| |
| $— |
| |
| $146.7 |
| |
| $4.2 |
| |
| $7.8 |
| |
| $0.2 |
| |
| $129.9 |
| |
| $2.2 |
|
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 followscontractual maturities, as of December 31, 2014:2016 and 2015 are as follows:
|
| | | | | | | | | | | | | | | |
| | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) |
| Less than 12 months |
| $0.2 |
| |
| $— |
| |
| $33.1 |
| |
| $0.2 |
|
| More than 12 months | — |
| | — |
| | 27.1 |
| | 0.5 |
|
| Total |
| $0.2 |
| |
| $— |
| |
| $60.2 |
| |
| $0.7 |
|
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
| less than 1 year |
| $16.7 |
| |
| $1.8 |
|
| 1 year - 5 years | 106.2 |
| | 145.2 |
|
| 5 years - 10 years | 161.2 |
| | 138.5 |
|
| 10 years - 15 years | 7.7 |
| | 2.4 |
|
| 15 years - 20 years | 1.0 |
| | 2.0 |
|
| 20 years+ | 16.5 |
| | 14.0 |
|
| Total |
| $309.3 |
| |
| $303.9 |
|
During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $197.4 million, $213 million, and $181.5 million, respectively. During the years ended December 31,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31,2016, 2015, and 2014, are as follows:
|
| | | | | | | |
| | 2015 | | 2014 |
| | (In Millions) |
| less than 1 year |
| $27.1 |
| |
| $12.0 |
|
| 1 year - 5 years | 124.0 |
| | 118.0 |
|
| 5 years - 10 years | 114.3 |
| | 112.5 |
|
| 10 years - 15 years | 39.3 |
| | 50.9 |
|
| 15 years - 20 years | 26.5 |
| | 24.2 |
|
| 20 years+ | 78.7 |
| | 68.2 |
|
| Total |
| $409.9 |
| |
| $385.8 |
|
During the years ended December 31, 2015, 2014, and 2013, proceeds from the dispositions of securities amounted to $123.5 million, $216.7 million, and $303.7 million, respectively. During the years ended December 31, 2015, 2014, and 2013, gross gains of $1.9$1.8 million, $2.2$5.9 million, and $22$8.7 million, respectively, and gross losses of $0.3$0.8 million, $0.3 million, and $0.2$0.3 million, respectively, were recorded in earnings.
System Energy Entergy Louisiana
System EnergyEntergy Louisiana holds debt and equity securities, classified as available-for-sale, in nuclear decommissioning trust accounts. The securities held as of December 31, 20152016 and 20142015 are summarized as follows:
| | | | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | 2016 | | 2015 |
| | | (In Millions) | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| 2015 | | | | | | | |
| | | | (In Millions) |
| Equity Securities | |
| $423.7 |
| |
| $179.2 |
| |
| $0.3 |
| |
| $715.9 |
| |
| $346.6 |
| |
| $— |
| |
| $632.4 |
| |
| $283.7 |
| |
| $0.2 |
|
| Debt Securities | | 277.8 |
| | 2.2 |
| | 2.3 |
| | 424.8 |
| | 8.0 |
| | 5.0 |
| | 409.9 |
| | 13.2 |
| | 2.4 |
|
| Total | |
| $701.5 |
| |
| $181.4 |
| |
| $2.6 |
| |
| $1,140.7 |
| |
| $354.6 |
| |
| $5.0 |
| |
| $1,042.3 |
| |
| $296.9 |
| |
| $2.6 |
|
| 2014 | | | | | | | |
| Equity Securities | |
| $424.5 |
| |
| $188.0 |
| |
| $— |
| |
| Debt Securities | | 255.3 |
| | 5.9 |
| | 0.3 |
| |
| Total | |
| $679.8 |
| |
| $193.9 |
| |
| $0.3 |
| |
The amortized cost of debt securities was $270.7$421.9 million as of December 31, 20152016 and $251$399.2 million as of December 31, 2014.2015. As of December 31, 2015,2016, the debt securities have an average coupon rate of approximately 2.16%3.78%, an average duration of approximately 4.865.59 years, and an average maturity of approximately 6.3410.99 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 equity 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, 2016 and 2015:
| | | | | | | | | | | | 2016 | | 2015 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $8.3 |
| |
| $0.2 |
| |
| $200.4 |
| |
| $2.2 |
|
| $— |
| |
| $— |
| |
| $198.8 |
| |
| $4.8 |
| |
| $9.4 |
| |
| $0.2 |
| |
| $124.0 |
| |
| $2.0 |
|
| More than 12 months | 0.9 |
| | 0.1 |
| | 5.0 |
| | 0.1 |
| — |
| | — |
| | 4.8 |
| | 0.2 |
| | — |
| | — |
| | 7.4 |
| | 0.4 |
|
| Total |
| $9.2 |
| |
| $0.3 |
| |
| $205.4 |
| |
| $2.3 |
|
| $— |
| |
| $— |
| |
| $203.6 |
| |
| $5.0 |
| |
| $9.4 |
| |
| $0.2 |
| |
| $131.4 |
| |
| $2.4 |
|
The fair value of debt securities, summarized by contractual maturities, as of December 31, 2016 and 2015 are as follows:
|
| | | | | | | |
| | 2016 | | 2015 |
| | (In Millions) |
| less than 1 year |
| $31.4 |
| |
| $27.1 |
|
| 1 year - 5 years | 99.1 |
| | 124.0 |
|
| 5 years - 10 years | 122.8 |
| | 114.3 |
|
| 10 years - 15 years | 41.4 |
| | 39.3 |
|
| 15 years - 20 years | 30.9 |
| | 26.5 |
|
| 20 years+ | 99.2 |
| | 78.7 |
|
| Total |
| $424.8 |
| |
| $409.9 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
During the years ended December 31, 2016, 2015, and 2014, proceeds from the dispositions of securities amounted to $219.2 million, $123.5 million, and $216.7 million, respectively. During the years ended December 31, 2016, 2015, and 2014, gross gains of $3.9 million, $1.9 million, and $2.2 million, respectively, and gross losses of $0.4 million, $0.3 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, 2016 and 2015 are summarized as follows:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | 2016 | | 2015 |
| | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses | | Fair Value | | Total Unrealized Gains | | Total Unrealized Losses |
| | | (In Millions) |
| Equity Securities | |
| $473.9 |
| |
| $221.9 |
| |
| $0.1 |
| |
| $423.7 |
| |
| $179.2 |
| |
| $0.3 |
|
| Debt Securities | | 306.6 |
| | 2.0 |
| | 4.5 |
| | 277.8 |
| | 2.2 |
| | 2.3 |
|
| Total | |
| $780.5 |
| |
| $223.9 |
| |
| $4.6 |
| |
| $701.5 |
| |
| $181.4 |
| |
| $2.6 |
|
The amortized cost of debt securities was $309.1 million as of December 31, 2016 and $270.7 million as of December 31, 2015. As of December 31, 2016, the debt securities have an average coupon rate of approximately 1.89%, an average duration of approximately 5.04 years, and an average maturity of approximately 6.30 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 equity 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, 2014:2016 and 2015:
| | | | | | | | | | | | 2016 | | 2015 |
| | Equity Securities | | Debt Securities | Equity Securities | | Debt Securities | | Equity Securities | | Debt Securities |
| | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses | | Fair Value | | Gross Unrealized Losses |
| | (In Millions) | (In Millions) |
| Less than 12 months |
| $0.1 |
| |
| $— |
| |
| $51.6 |
| |
| $0.2 |
|
| $— |
| |
| $— |
| |
| $220.9 |
| |
| $4.4 |
| |
| $8.3 |
| |
| $0.2 |
| |
| $200.4 |
| |
| $2.2 |
|
| More than 12 months | — |
| | — |
| | 6.5 |
| | 0.1 |
| — |
| | 0.1 |
| | 0.8 |
| | 0.1 |
| | 0.9 |
| | 0.1 |
| | 5.0 |
| | 0.1 |
|
| Total |
| $0.1 |
| |
| $— |
| |
| $58.1 |
| |
| $0.3 |
|
| $— |
| |
| $0.1 |
| |
| $221.7 |
| |
| $4.5 |
| |
| $9.2 |
| |
| $0.3 |
| |
| $205.4 |
| |
| $2.3 |
|
Entergy Corporation and Subsidiaries
Notes to Financial Statements
The fair value of debt securities, summarized by contractual maturities, as of December 31, 20152016 and 20142015 are as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| less than 1 year |
| $2.0 |
| |
| $33.5 |
|
| $6.6 |
| |
| $2.0 |
|
| 1 year - 5 years | 181.2 |
| | 139.7 |
| 188.2 |
| | 181.2 |
|
| 5 years - 10 years | 63.0 |
| | 53.5 |
| 78.5 |
| | 63.0 |
|
| 10 years - 15 years | 4.4 |
| | 3.4 |
| 1.3 |
| | 4.4 |
|
| 15 years - 20 years | 1.6 |
| | 3.2 |
| 7.8 |
| | 1.6 |
|
| 20 years+ | 25.6 |
| | 22.0 |
| 24.2 |
| | 25.6 |
|
| Total |
| $277.8 |
| |
| $255.3 |
|
| $306.6 |
| |
| $277.8 |
|
During the years ended December 31, 2016, 2015, 2014, and 2013,2014, proceeds from the dispositions of securities amounted to $499.3 million, $390.4 million, $392.9 million, and $215.5$392.9 million, respectively. During the years ended December 31, 2016, 2015, 2014, and 2013,2014, gross gains of $3.5 million, $3.3 million, $1.8 million, and $1.5$1.8 million, respectively, and gross losses of $1.7 million, $0.5 million, $0.9 million, and $1.3$0.9 million, respectively, were recorded in earnings.
Other-than-temporary impairments and unrealized gains and losses
Entergy evaluates investment securities in the Entergy Arkansas, Entergy Louisiana, and System Energy evaluateWholesale Commodities’ nuclear decommissioning trust funds with 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.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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, 2016, 2015, 2014, and 2013.2014. 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. Entergy did not record material charges to other income in 2016, 2015, 2014, and 2013,2014, respectively, resulting from the recognition of the other-than-temporary impairment of certain equity securities held in its decommissioning trust funds.
NOTE 18.17. VARIABLE INTEREST ENTITIES (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Under applicable authoritative accounting guidance, a variable interest entity (VIE) is an entity that conducts a business or holds property that possesses any of the following characteristics: an insufficient amount of equity at risk to finance its activities, equity owners who do not have the power to direct the significant activities of the 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 VIE’s primary beneficiary. The primary beneficiary of a VIE is the entity that has the power to direct the activities of the VIE that most significantly affect the VIE’s economic performance, and has the obligation to absorb losses or has the right to residual returns that would potentially be significant to the entity.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy Arkansas, 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 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 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 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 Corporation and Subsidiaries
Notes to Financial Statements
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 canceled 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.
Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly-owned and consolidated by Entergy New Orleans, is a variable interest entity, and Entergy New Orleans is the primary beneficiary. In July 2015,
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Entergy New Orleans Storm Recovery Funding issued storm cost recovery bonds to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs, including carrying costs, the costs of funding and replenishing the storm recovery reserve, and up-front financing costs associated with the securitization. With the proceeds, Entergy New Orleans Storm Recovery Funding purchased from Entergy New Orleans 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 New Orleans balance sheet. The creditors of Entergy New Orleans do not have recourse to the assets or revenues of Entergy New Orleans Storm Recovery Funding, including the storm recovery property, and the creditors of Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Entergy New Orleans has no payment obligations to Entergy New Orleans Storm Recovery Funding except to remit storm recovery charge collections. See Note 5 to the financial statements for additional details regarding the securitization bonds.
Entergy Louisiana and System Energy are alsowas considered to each hold a variable interest in the lessorslessor from which they leaseit leased an undivided interestsinterest in the Waterford 3 nuclear plant. After Entergy Louisiana acquired a beneficial interest in the leased assets in March 2016, however, the lessor was no longer considered a variable interest entity. Entergy Louisiana made payments on its lease, including interest, of $9.2 million through March 2016, $28.8 million in 2015, and $31 million in 2014. See Note 10 to the financial statements for a discussion of Entergy Louisiana’s purchase of the Waterford 3 leased assets.
System Energy is considered to hold a variable interest in the lessor from which it leases an undivided interest in the Grand Gulf nuclear plants, respectively. Entergy Louisiana andplant. System Energy areis the lesseeslessee under these arrangements,this arrangement, which areis described in more detail in Note 10 to the financial statements. Entergy Louisiana made payments on its lease, including interest, of $28.8 million in 2015, $31 million in 2014, and $26.3 million in 2013. System Energy made payments on its lease, including interest, of $17.2 million in 2016, $52.3 million in 2015, and $51.6 million in 2014, and $50.5 million in 2013.2014. The lessors are bankslessor is a bank acting in the capacity of owner trustee for the benefit of equity investors in the transactionstransaction pursuant to trust agreementsagreement entered solely for the purpose of facilitating the lease transactions.transaction. It is possible that Entergy Louisiana and System Energy may be considered as the primary beneficiary of the lessors,lessor, but Entergy is unable to apply the authoritative accounting guidance with respect to these VIEsthis VIE because the lessors arelessor is not required to, and could not, provide the necessary financial information to consolidate the lessors.lessor. Because Entergy accounts for thesethis leasing arrangementsarrangement as a capital financings,financing, however, Entergy believes that consolidating the lessorslessor would not materially affect the financial statements. In the unlikely event of default under a lease, remedies available to the lessor include payment by the lessee of the fair value of the
Entergy Corporation and Subsidiaries
Notes to Financial Statements
undivided interest in the plant, payment of the present value of the basic rent payments, or payment of a predetermined casualty value. Entergy believes, however, that the obligations recorded on the balance sheetssheet materially represent eachthe company’s potential exposure to loss.
Entergy has also reviewed various lease arrangements, power purchase agreements, including agreements for renewable power, and other agreements that represent variable interests in other legal entities which have been determined to be variable interest entities. 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 VIE’s economic performance, or it does not have the obligation to absorb losses or the right to residual returns that would potentially be significant to the entity, or both.
NOTE 19.18. TRANSACTIONS WITH AFFILIATES (Entergy Arkansas, 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 receive management, technical, advisory, operating, and administrative services from Entergy Services; and receive management, technical, and operating services from Entergy Operations. These transactions are on an “at cost” basis. In addition, Entergy Power sold electricity to Entergy Arkansas, Entergy Louisiana, and Entergy New Orleans prior to the expiration of the contract in 2013.
As described in Note 1 to the financial statements, all of System Energy’s operating revenues consist of billings to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
As described in Note 4 to the financial statements, the Registrant Subsidiaries participate in Entergy’s money pool and earn interest income from the money pool. As described in Note 2 to the financial statements, Entergy Louisiana receives preferred membership interest 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 Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) | (In Millions) |
| 2016 | |
| $49.4 |
| |
| $376.6 |
| |
| $2.9 |
| |
| $30.3 |
| |
| $180.2 |
| |
| $548.3 |
|
| 2015 |
| $127.9 |
| |
| $420.2 |
| |
| $86.0 |
| |
| $66.1 |
| |
| $259.1 |
| |
| $632.4 |
|
| $127.9 |
| |
| $420.2 |
| |
| $86.0 |
| |
| $66.1 |
| |
| $259.1 |
| |
| $632.4 |
|
| 2014 |
| $131.2 |
| |
| $440.2 |
| |
| $169.8 |
| |
| $80.1 |
| |
| $316.1 |
| |
| $664.4 |
|
| $131.2 |
| |
| $440.2 |
| |
| $169.8 |
| |
| $80.1 |
| |
| $316.1 |
| |
| $664.4 |
|
| 2013 |
| $349.9 |
| |
| $329.5 |
| |
| $107.3 |
| |
| $28.1 |
| |
| $369.4 |
| |
| $735.1 |
| |
Intercompany Operating Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2016 |
| $467.4 |
| |
| $670.8 |
| |
| $256.5 |
| |
| $276.7 |
| |
| $343.7 |
| |
| $146.0 |
|
| 2015 |
| $508.5 |
| |
| $929.4 |
| |
| $331.8 |
| |
| $278.4 |
| |
| $413.7 |
| |
| $155.1 |
|
| 2014 |
| $596.6 |
| |
| $1,027.6 |
| |
| $367.6 |
| |
| $249.5 |
| |
| $445.3 |
| |
| $156.7 |
|
Intercompany Interest and Investment Income
|
| | | | | | | | | | | |
| | Entergy Louisiana | | Entergy Mississippi | | System Energy |
| | (In Millions) |
| | | | | | |
| 2016 |
| $127.7 |
| |
| $0.1 |
| |
| $0.1 |
|
| 2015 |
| $133.6 |
| |
| $— |
| |
| $— |
|
| 2014 |
| $117.9 |
| |
| $— |
| |
| $— |
|
Transactions with Equity Method Investees
EWO Marketing, LLC, an indirect wholly-owned subsidiary of Entergy, paid capacity charges and gas transportation to RS Cogen in the amounts of $24.7 million in 2016, $24.5 million in 2015, and $23.1 million in 2014.
Entergy’s operating transactions with its other equity method investees were not significant in 2016, 2015, or 2014.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Intercompany Operating Expenses
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | Entergy Arkansas (a) | | Entergy Louisiana (b) | | Entergy Mississippi | | Entergy New Orleans (c) | | Entergy Texas | | System Energy |
| | (In Millions) |
| 2015 |
| $508.5 |
| |
| $929.4 |
| |
| $331.8 |
| |
| $278.4 |
| |
| $413.7 |
| |
| $155.1 |
|
| 2014 |
| $596.6 |
| |
| $1,027.6 |
| |
| $367.6 |
| |
| $249.5 |
| |
| $445.3 |
| |
| $156.7 |
|
| 2013 |
| $656.1 |
| |
| $1,171.9 |
| |
| $399.0 |
| |
| $288.7 |
| |
| $418.1 |
| |
| $175.2 |
|
| |
(a) | Includes power purchased from Entergy Power of $3.3 million in 2013. The contract with Entergy Power expired in May 2013. |
| |
(b) | Includes power purchased from RS Cogen of $3.2 million in 2013 and power purchased from Entergy Power of $8.1 million in 2013. The contract with Entergy Power expired in May 2013. |
| |
(c) | Includes power purchased from Entergy Power of $8 million in 2013. The contract with Entergy Power expired in May 2013. |
Intercompany Interest and Investment Income
|
| | | | |
| | | Entergy Louisiana |
| | | (In Millions) |
|
| | | |
| 2015 | |
| $133.6 |
|
| 2014 | |
| $117.9 |
|
| 2013 | |
| $105.7 |
|
NOTE 20.19. QUARTERLY FINANCIAL DATA (UNAUDITED) (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Operating results for the four quarters of 20152016 and 20142015 for Entergy Corporation and subsidiaries were:
| | | | Operating
Revenues | | Operating Income (Loss) | | Consolidated Net Income (Loss) | | Net Income (Loss) Attributable to Entergy Corporation | Operating Revenues | | Operating Income (Loss) | | Consolidated Net Income (Loss) | | Net Income (Loss) Attributable to Entergy Corporation |
| | (In Thousands) | (In Thousands) |
| 2016: | | | | |
| First Quarter | |
| $2,609,852 |
| |
| $498,218 |
| |
| $235,242 |
| |
| $229,966 |
|
| Second Quarter | |
| $2,462,562 |
| |
| $442,258 |
| |
| $572,590 |
| |
| $567,314 |
|
| Third Quarter | |
| $3,124,703 |
| |
| $772,060 |
| |
| $393,204 |
| |
| $388,170 |
|
| Fourth Quarter | |
| $2,648,528 |
| |
| ($2,599,001 | ) | |
| ($1,765,539 | ) | |
| ($1,769,068 | ) |
| 2015: | | | | | | |
| First Quarter |
| $2,920,090 |
| |
| $542,769 |
| |
| $302,929 |
| |
| $298,050 |
|
| $2,920,090 |
| |
| $542,769 |
| |
| $302,929 |
| |
| $298,050 |
|
| Second Quarter |
| $2,713,231 |
| |
| $377,383 |
| |
| $153,722 |
| |
| $148,843 |
|
| $2,713,231 |
| |
| $377,383 |
| |
| $153,722 |
| |
| $148,843 |
|
| Third Quarter |
| $3,371,406 |
| |
| ($965,016 | ) | |
| ($718,233 | ) | |
| ($723,027 | ) |
| $3,371,406 |
| |
| ($965,016 | ) | |
| ($718,233 | ) | |
| ($723,027 | ) |
| Fourth Quarter |
| $2,508,523 |
| |
| ($254,300 | ) | |
| $104,849 |
| |
| $99,573 |
|
| $2,508,523 |
| |
| ($254,300 | ) | |
| $104,849 |
| |
| $99,573 |
|
| 2014: | | | | |
| First Quarter |
| $3,208,843 |
| |
| $739,877 |
| |
| $406,053 |
| |
| $401,174 |
| |
| Second Quarter |
| $2,996,650 |
| |
| $454,477 |
| |
| $194,281 |
| |
| $189,383 |
| |
| Third Quarter |
| $3,458,110 |
| |
| $492,859 |
| |
| $234,916 |
| |
| $230,037 |
| |
| Fourth Quarter |
| $2,831,318 |
| |
| $319,674 |
| |
| $125,006 |
| |
| $120,127 |
| |
Earnings (loss) per average common share
|
| | | | | | | | | | | | | | | |
| | 2016 | | 2015 |
| | Basic | | Diluted | | Basic | | Diluted |
| First Quarter |
| $1.29 |
| |
| $1.28 |
| |
| $1.66 |
| |
| $1.65 |
|
| Second Quarter |
| $3.17 |
| |
| $3.16 |
| |
| $0.83 |
| |
| $0.83 |
|
| Third Quarter |
| $2.17 |
| |
| $2.16 |
| |
| ($4.04 | ) | |
| ($4.04 | ) |
| Fourth Quarter |
| ($9.89 | ) | |
| ($9.86 | ) | |
| $0.56 |
| |
| $0.56 |
|
Results of operations for 2016 include $2,836 million ($1,829 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ Palisades, Indian Point 2, and Indian Point 3 plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. Results of operations for 2016 also include a reduction of income tax expense, net of unrecognized tax benefits, of $238 million as a result of a tax election to treat a subsidiary that owns one of the Entergy Wholesale Commodities nuclear power plants as a corporation for federal income tax purposes; income tax benefits as a result of the settlement of the 2010-2011 IRS audit, including a $75 million tax benefit recognized by Entergy Louisiana related to the treatment of the Vidalia purchased power agreement and a $54 million net benefit recognized by Entergy Louisiana related to the treatment of proceeds received in 2010 for the financing of Hurricane Gustav and Hurricane Ike storm costs pursuant to Louisiana Act 55; and a reduction in expenses of $100 million ($64 million net-of-tax) due to the effects of recording in 2016 the final court decisions in several lawsuits against the DOE related to spent nuclear fuel storage costs. See Note 3 to the financial statements for additional discussion of the income tax items and Note 8 to the financial statements for discussion of the spent nuclear fuel litigation.
Results of operations for 2015 includes $2,036 million ($1,317 million net-of-tax) of impairment and related charges primarily to write down the carrying values of the Entergy Wholesale Commodities’ FitzPatrick, Pilgrim, and Palisades plants and related assets to their fair values. See Note 14 to the financial statements for further discussion of the impairment and related charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Earnings per Average Common Share
|
| | | | | | | | | | | | | | | |
| | 2015 | | 2014 |
| | Basic | | Diluted | | Basic | | Diluted |
| First Quarter |
| $1.66 |
| |
| $1.65 |
| |
| $2.24 |
| |
| $2.24 |
|
| Second Quarter |
| $0.83 |
| |
| $0.83 |
| |
| $1.06 |
| |
| $1.05 |
|
| Third Quarter |
| ($4.04 | ) | |
| ($4.04 | ) | |
| $1.28 |
| |
| $1.27 |
|
| Fourth Quarter |
| $0.56 |
| |
| $0.56 |
| |
| $0.67 |
| |
| $0.66 |
|
Third quarter 2015 results of operations includes $1,642 million ($1,062 million net-of-tax) of impairment and related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. Fourth quarter 2015 results of operations includes $396 million ($256 million net-of-tax) of impairment and related changes to write down the carrying values of the Palisades plant and related assets to their fair values. See Note 1 to the financial statements for further discussion of the charges. As a result of the Entergy Louisiana and Entergy Gulf States Louisiana business combination, results of operations for 2015 also include two items that occurred in October 2015: 1) a deferred tax asset and resulting net increase in tax basis of approximately $334 million and 2) a regulatory liability of $107 million ($66 million net-of-tax) as a result of customer credits to be realized by electric customers of Entergy Louisiana, consistent with the terms of an agreement with the LPSC.stipulated settlement in the business combination proceeding. See Note 2 to the financial statements for further discussion of the business combination and customer credits. Results of operations for fourth quarter 2015 also include the sale in December 2015 of the 583 MW Rhode Island State Energy Center for a realized gain of $154 million ($100 million net-of-tax) on the sale and the $77 million ($47 million net-of-tax) write-off and relatedregulatory charges to recognize that a portion of the assets associated with Entergy Louisiana’sthe Waterford 3 replacement steam generator project is no longer probable of recovery. See Note 2 to the financial statements for further discussion of the Waterford 3 write-off.
Results of operations for third quarter 2014 include $113 million ($74 million net-of-tax) of charges related to Vermont Yankee, including the effects of an updated decommissioning cost study along with reassessment of assumptions regarding the timing of decommissioning cash flows and severance and employee retention costs. See Note 1 to the financial statements for further discussion of these charges. Results of operations for third quarter 2014 also include the $61 million ($40 million net-of-tax) write-off of Entergy Mississippi’s regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for further discussion of the new nuclear generation development costs and the joint stipulation.
Entergy Corporation and Subsidiaries
Notes to Financial Statements
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 2016 and 2015 and 2014 were:
Operating Revenues
| | | | Entergy Arkansas | | Entergy Louisiana (a) | | Entergy Mississippi | | Entergy New Orleans (b) | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2016: | | | | | | | | | | | | |
| First Quarter | |
| $465,373 |
| |
| $955,145 |
| |
| $263,046 |
| |
| $149,340 |
| |
| $378,304 |
| |
| $137,693 |
|
| Second Quarter | |
| $504,252 |
| |
| $999,034 |
| |
| $248,138 |
| |
| $164,920 |
| |
| $412,922 |
| |
| $151,323 |
|
| Third Quarter | |
| $654,599 |
| |
| $1,249,452 |
| |
| $309,739 |
| |
| $201,336 |
| |
| $442,085 |
| |
| $114,039 |
|
| Fourth Quarter | |
| $462,384 |
| |
| $973,417 |
| |
| $273,726 |
| |
| $149,867 |
| |
| $382,308 |
| |
| $145,236 |
|
| 2015: | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter |
| $511,253 |
| |
| $1,069,191 |
| |
| $360,815 |
| |
| $156,626 |
| |
| $411,211 |
| |
| $156,039 |
|
| $511,253 |
| |
| $1,069,191 |
| |
| $360,815 |
| |
| $156,626 |
| |
| $411,211 |
| |
| $156,039 |
|
| Second Quarter |
| $551,809 |
| |
| $1,074,598 |
| |
| $344,975 |
| |
| $160,752 |
| |
| $402,921 |
| |
| $163,101 |
|
| $551,809 |
| |
| $1,074,598 |
| |
| $344,975 |
| |
| $160,752 |
| |
| $402,921 |
| |
| $163,101 |
|
| Third Quarter |
| $714,353 |
| |
| $1,298,482 |
| |
| $410,743 |
| |
| $209,733 |
| |
| $498,249 |
| |
| $155,899 |
|
| $714,353 |
| |
| $1,298,482 |
| |
| $410,743 |
| |
| $209,733 |
| |
| $498,249 |
| |
| $155,899 |
|
| Fourth Quarter |
| $476,149 |
| |
| $974,875 |
| |
| $280,452 |
| |
| $144,335 |
| |
| $394,822 |
| |
| $157,366 |
|
| $476,149 |
| |
| $974,875 |
| |
| $280,452 |
| |
| $144,335 |
| |
| $394,822 |
| |
| $157,366 |
|
| 2014: | | | | | | | | | | | | |
| First Quarter |
| $514,981 |
| |
| $1,074,334 |
| |
| $348,196 |
| |
| $195,866 |
| |
| $440,256 |
| |
| $157,667 |
| |
| Second Quarter |
| $511,522 |
| |
| $1,231,428 |
| |
| $370,638 |
| |
| $180,320 |
| |
| $482,932 |
| |
| $163,830 |
| |
| Third Quarter |
| $627,153 |
| |
| $1,421,028 |
| |
| $425,341 |
| |
| $198,524 |
| |
| $528,508 |
| |
| $172,151 |
| |
| Fourth Quarter |
| $518,735 |
| |
| $1,013,714 |
| |
| $380,018 |
| |
| $160,482 |
| |
| $400,286 |
| |
| $170,716 |
| |
| |
(a) | See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, operating revenues are higher by $429,097 in the first quarter 2015, $406,974 in the second quarter 2015, $488,543 in the third quarter 2015, $450,840 in the first quarter 2014, $495,020 in the second quarter 2014, $550,847 in the third quarter 2014, and $417,916 in the fourth quarter 2014. |
| |
(b) | See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, operating revenues are higher by $9,726 in the first quarter 2015, $10,258 in the second quarter 2015, $9,299 in the first quarter 2014, $10,331 in the second quarter 2014, $15,553 in the third quarter 2014, and $9,924 in the fourth quarter 2014. |
Operating Income (Loss)
| | | | Entergy Arkansas | | Entergy Louisiana (c) | | Entergy Mississippi | | Entergy New Orleans (d) | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2016: | | | | | | | | | | | | |
| First Quarter | |
| $54,378 |
| |
| $181,618 |
| |
| $41,573 |
| |
| $21,880 |
| |
| $41,269 |
| |
| $47,466 |
|
| Second Quarter | |
| $73,447 |
| |
| $193,752 |
| |
| $61,890 |
| |
| $26,913 |
| |
| $58,039 |
| |
| $45,020 |
|
| Third Quarter | |
| $188,660 |
| |
| $312,951 |
| |
| $88,312 |
| |
| $42,279 |
| |
| $107,964 |
| |
| $43,886 |
|
| Fourth Quarter | |
| $29,843 |
| |
| $111,066 |
| |
| $32,464 |
| |
| $8,807 |
| |
| $38,338 |
| |
| $44,781 |
|
| 2015: | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter |
| $36,656 |
| |
| $185,776 |
| |
| $54,839 |
| |
| $20,745 |
| |
| $44,013 |
| |
| $47,784 |
|
| $36,656 |
| |
| $185,776 |
| |
| $54,839 |
| |
| $20,745 |
| |
| $44,013 |
| |
| $47,784 |
|
| Second Quarter |
| $55,149 |
| |
| $191,068 |
| |
| $58,086 |
| |
| $20,154 |
| |
| $44,064 |
| |
| $45,470 |
|
| $55,149 |
| |
| $191,068 |
| |
| $58,086 |
| |
| $20,154 |
| |
| $44,064 |
| |
| $45,470 |
|
| Third Quarter |
| $109,236 |
| |
| $294,436 |
| |
| $74,264 |
| |
| $34,734 |
| |
| $86,624 |
| |
| $47,135 |
|
| $109,236 |
| |
| $294,436 |
| |
| $74,264 |
| |
| $34,734 |
| |
| $86,624 |
| |
| $47,135 |
|
| Fourth Quarter |
| ($21,635 | ) | |
| $47,052 |
| |
| $24,717 |
| |
| $9,337 |
| |
| $8,944 |
| |
| $45,239 |
|
| ($21,635 | ) | |
| $47,052 |
| |
| $24,717 |
| |
| $9,337 |
| |
| $8,944 |
| |
| $45,239 |
|
| 2014: | | | | | | | | | | | | |
| First Quarter |
| $66,360 |
| |
| $167,633 |
| |
| $57,132 |
| |
| $15,822 |
| |
| $43,056 |
| |
| $52,029 |
| |
| Second Quarter |
| $68,970 |
| |
| $170,526 |
| |
| $59,063 |
| |
| $13,421 |
| |
| $53,158 |
| |
| $56,547 |
| |
| Third Quarter |
| $115,357 |
| |
| $257,293 |
| |
| $9,403 |
| |
| $28,396 |
| |
| $82,911 |
| |
| $58,484 |
| |
| Fourth Quarter |
| $19,317 |
| |
| $82,381 |
| |
| $61,162 |
| |
| $317 |
| |
| $29,590 |
| |
| $54,056 |
| |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
| |
(c) | See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, operating income is higher by $79,389 in the first quarter 2015, $65,901 in the second quarter 2015, $100,753 in the third quarter 2015, $82,576 in the first quarter 2014, $70,350 in the second quarter 2014, $96,698 in the third quarter 2014, and $43,766 in the fourth quarter 2014. |
| |
(d) | See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, operating income is higher by $1,177 in the first quarter 2015, $1,504 in the second quarter 2015, $541 in the first quarter 2014, $559 in the second quarter 2014, $3,530 in the third quarter 2014, and $856 in the fourth quarter 2014. |
Net Income (Loss)
| | | | Entergy Arkansas | | Entergy Louisiana (e) | | Entergy Mississippi | | Entergy New Orleans (f) | | Entergy Texas | | System Energy | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy |
| | (In Thousands) | (In Thousands) |
| 2016: | | | | | | | | | | | | |
| First Quarter | |
| $19,294 |
| |
| $111,606 |
| |
| $17,118 |
| |
| $11,167 |
| |
| $14,562 |
| |
| $25,958 |
|
| Second Quarter | |
| $33,891 |
| |
| $253,325 |
| |
| $32,194 |
| |
| $11,843 |
| |
| $24,058 |
| |
| $25,090 |
|
| Third Quarter | |
| $110,148 |
| |
| $189,506 |
| |
| $46,612 |
| |
| $23,701 |
| |
| $56,133 |
| |
| $22,370 |
|
| Fourth Quarter | |
| $3,879 |
| |
| $67,610 |
| |
| $13,260 |
| |
| $2,138 |
| |
| $12,785 |
| |
| $23,326 |
|
| 2015: | | | | | | | | | | | | | | | | | | | | | | |
| First Quarter |
| $17,865 |
| |
| $126,109 |
| |
| $24,935 |
| |
| $11,292 |
| |
| $16,591 |
| |
| $25,533 |
|
| $17,865 |
| |
| $126,109 |
| |
| $24,935 |
| |
| $11,292 |
| |
| $16,591 |
| |
| $25,533 |
|
| Second Quarter |
| $21,525 |
| |
| $108,981 |
| |
| $26,279 |
| |
| $10,895 |
| |
| $14,890 |
| |
| $21,860 |
|
| $21,525 |
| |
| $108,981 |
| |
| $26,279 |
| |
| $10,895 |
| |
| $14,890 |
| |
| $21,860 |
|
| Third Quarter |
| $55,662 |
| |
| $187,140 |
| |
| $36,576 |
| |
| $19,163 |
| |
| $43,314 |
| |
| $25,223 |
|
| $55,662 |
| |
| $187,140 |
| |
| $36,576 |
| |
| $19,163 |
| |
| $43,314 |
| |
| $25,223 |
|
| Fourth Quarter |
| ($20,780 | ) | |
| $24,409 |
| |
| $4,918 |
| |
| $3,575 |
| |
| ($5,170 | ) | |
| $38,702 |
|
| ($20,780 | ) | |
| $24,409 |
| |
| $4,918 |
| |
| $3,575 |
| |
| ($5,170 | ) | |
| $38,702 |
|
| 2014: | | | | | | | | | | | | |
| First Quarter |
| $28,370 |
| |
| $104,850 |
| |
| $25,839 |
| |
| $8,276 |
| |
| $13,165 |
| |
| $24,619 |
| |
| Second Quarter |
| $29,005 |
| |
| $105,838 |
| |
| $26,564 |
| |
| $6,406 |
| |
| $18,585 |
| |
| $25,931 |
| |
| Third Quarter |
| $62,980 |
| |
| $179,356 |
| |
| ($6,464 | ) | |
| $15,950 |
| |
| $39,559 |
| |
| $26,730 |
| |
| Fourth Quarter |
| $1,037 |
| |
| $55,978 |
| |
| $28,882 |
| |
| $398 |
| |
| $3,495 |
| |
| $19,054 |
| |
| |
(e) | See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, net income is higher by $53,845 in the first quarter 2015, $33,963 in the second quarter 2015, $68,140 in the third quarter 2015, $46,472 in the first quarter 2014, $36,171 in the second quarter 2014, $55,535 in the third quarter 2014, and $24,313 in the fourth quarter 2014. |
| |
(f) | See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, net income is higher (lower) by $238 in the first quarter 2015, $393 in the second quarter 2015, ($18) in the first quarter 2014, $32 in the second quarter 2014, $2,018 in the third quarter 2014, and $291 in the fourth quarter 2014. |
Entergy Corporation and Subsidiaries
Notes to Financial Statements
Earnings (Loss) Applicable to Common Equity
|
| | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana (g) | | Entergy Mississippi | | Entergy New Orleans (h) |
| | (In Thousands) |
| 2015: | | | | | | | |
| First Quarter |
| $16,147 |
| |
| $124,165 |
| |
| $24,228 |
| |
| $11,051 |
|
| Second Quarter |
| $19,807 |
| |
| $107,037 |
| |
| $25,572 |
| |
| $10,654 |
|
| Third Quarter |
| $53,944 |
| |
| $185,290 |
| |
| $35,869 |
| |
| $18,922 |
|
| Fourth Quarter |
| ($22,499 | ) | |
| $24,410 |
| |
| $4,211 |
| |
| $3,333 |
|
| 2014: | | | | | | | |
| First Quarter |
| $26,652 |
| |
| $102,906 |
| |
| $25,132 |
| |
| $8,035 |
|
| Second Quarter |
| $27,287 |
| |
| $103,872 |
| |
| $25,857 |
| |
| $6,165 |
|
| Third Quarter |
| $61,262 |
| |
| $177,412 |
| |
| ($7,171 | ) | |
| $15,709 |
|
| Fourth Quarter |
| ($682 | ) | |
| $54,036 |
| |
| $28,175 |
| |
| $156 |
|
| |
(g) | See Note 1 to the financial statements for discussion of the business combination of Entergy Louisiana and Entergy Gulf States Louisiana. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. As a result, earnings applicable to common equity is higher by $53,639 in the first quarter 2015, $33,757 in the second quarter 2015, $67,970 in the third quarter 2015, $46,266 in the first quarter 2014, $35,962 in the second quarter 2014, $55,329 in the third quarter 2014, and $24,107 in the fourth quarter 2014. |
| |
(h) | See Note 1 to the financial statements for discussion of the transfer of Entergy Louisiana’s Algiers assets to Entergy New Orleans. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report. As a result, earnings applicable to common equity is higher (lower) by $238 in the first quarter 2015, $393 in the second quarter 2015, ($18) in the first quarter 2014, $32 in the second quarter 2014, $2,018 in the third quarter 2014, and $290 in the fourth quarter 2014. |
|
| | | | | | | | | | | | | | | |
| | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans |
| | (In Thousands) |
| 2016: | | | | | | | |
| First Quarter |
| $17,576 |
| |
| $111,606 |
| |
| $16,411 |
| |
| $10,926 |
|
| Second Quarter |
| $32,173 |
| |
| $253,325 |
| |
| $31,487 |
| |
| $11,602 |
|
| Third Quarter |
| $108,672 |
| |
| $189,506 |
| |
| $45,905 |
| |
| $23,460 |
|
| Fourth Quarter |
| $3,521 |
| |
| $67,610 |
| |
| $12,938 |
| |
| $1,896 |
|
| 2015: | | | | | | | |
| First Quarter |
| $16,147 |
| |
| $124,165 |
| |
| $24,228 |
| |
| $11,051 |
|
| Second Quarter |
| $19,807 |
| |
| $107,037 |
| |
| $25,572 |
| |
| $10,654 |
|
| Third Quarter |
| $53,944 |
| |
| $185,290 |
| |
| $35,869 |
| |
| $18,922 |
|
| Fourth Quarter |
| ($22,499 | ) | |
| $24,410 |
| |
| $4,211 |
| |
| $3,333 |
|
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
ENTERGY’S BUSINESS
Entergy is an integrated energy company engaged primarily in electric power production and retail distribution operations. Entergy owns and operates power plants with approximately 30,000 MW of electric generating capacity, including nearly 10,000 MW of nuclear power. Entergy delivers electricity to 2.82.9 million utility customers in Arkansas, Louisiana, Mississippi, and Texas. Entergy had annual revenues of $11.5$10.8 billion in 20152016 and had more than 13,000 employees as of December 31, 2015.2016.
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 operation of a small natural gas distribution business.
The Entergy Wholesale Commodities business segment includes the ownership, operation, and decommissioning of nuclear power plants located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. On December 29, 2014, the Vermont Yankee plant ceased power production and entered its decommissioning phase. In October 2015, Entergy determined that it will close the Pilgrim plant no later than June 1, 2019 and the FitzPatrick plant at the end of its current fuel cycle, planned for January 27, 2017. Entergy Wholesale Commodities also provides services to other nuclear power plant owners and owns interests in non-nuclear power plants that sell the electric power produced by those plants to wholesale customers. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Wholesale Commodities Exit from the Merchant Power Business” for discussion of the operation and planned shutdown or sale of each of the Entergy Wholesale Commodities nuclear power plants.
See Note 13 to the financial statements for financial information regarding Entergy’s business segments.
Strategy
Entergy’s mission is to operate a world-class energy business that creates sustainable value for its owners, customers, employees, and communities. Entergy aspires to achieve top quartile total shareholder returns in a socially and environmentally responsible fashion by leveraging the scale and expertise inherent in its core utility and nuclear 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, risk management, and engaged employees. Entergy also continually seeks opportunities to grow its utility business to benefit all stakeholders and to optimize its portfolio of assets in an ever-dynamic market through periodic buy, build, hold, or disposal decisions. To accomplish this, Entergy has established strategic imperatives for each business segment. For the Utility, the strategic imperative is to modernize its operations, and maintain reliability, and forbetter serve its customers while growing the business. For Entergy Wholesale Commodities, the strategic imperative is to continue to manage the risk inof its operating portfolio as Entergy completes its exit from the merchant power business.
Utility
The Utility business segment includes five wholly-owned retail electric utility subsidiaries: Entergy Arkansas, 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 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 five 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 because all of its transactions are at wholesale. The overall generation portfolio of the Utility, which relies heavily on natural gas and nuclear generation, is consistent with Entergy’s strong support for the environment.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Customers
As of December 31, 2015,2016, 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 | | 705 |
| | 25 | % | | | | | Portions of Arkansas | | 707 |
| | 25 | % | | | | |
| Entergy Louisiana | Portions of Louisiana | | 1,064 |
| | 37 | % | | 94 |
| | 47 | % | Portions of Louisiana | | 1,072 |
| | 37 | % | | 93 |
| | 47 | % |
| Entergy Mississippi | Portions of Mississippi | | 445 |
| | 16 | % | | | | | Portions of Mississippi | | 447 |
| | 16 | % | | | | |
| Entergy New Orleans | City of New Orleans | | 197 |
| | 7 | % | | 105 |
| | 53 | % | City of New Orleans | | 198 |
| | 7 | % | | 106 |
| | 53 | % |
| Entergy Texas | Portions of Texas | | 434 |
| | 15 | % | | | | | Portions of Texas | | 444 |
| | 15 | % | | | | |
| Total customers | | | 2,845 |
| | 100 | % | | 199 |
| | 100 | % | | | 2,868 |
| | 100 | % | | 199 |
| | 100 | % |
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 July 29, 2015,21, 2016, Entergy reached a 20152016 peak demand of 21,73021,387 MWh, compared to the 20142015 peak of 20,47221,730 MWh recorded on August 22, 2014.July 29, 2015. Selected electric energy sales data is shown in the table below:
Selected 20152016 Electric Energy Sales Data
| | | | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) | Entergy Arkansas | | Entergy Louisiana | | Entergy Mississippi | | Entergy New Orleans | | Entergy Texas | | System Energy | | Entergy (a) |
| | (In GWh) | (In GWh) |
Sales to retail customers | 21,160 |
| | 54,568 |
| | 13,290 |
| | 5,845 |
| | 17,749 |
| | — |
| | 112,312 |
| 20,638 |
| | 54,599 |
| | 13,443 |
| | 5,734 |
| | 18,182 |
| | — |
| | 112,595 |
|
| Sales for resale: | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Affiliates | 2,239 |
| | 7,500 |
| | 1,419 |
| | 1,644 |
| | 5,853 |
| | 10,547 |
| | — |
| 1,609 |
| | 7,345 |
| | — |
| | 1,071 |
| | 4,625 |
| | 5,384 |
| | — |
|
| Others | 7,980 |
| | 770 |
| | 261 |
| | 11 |
| | 254 |
| | — |
| | 9,274 |
| 7,115 |
| | 1,690 |
| | 1,021 |
| | 141 |
| | 1,086 |
| | — |
| | 11,054 |
|
| Total | 31,379 |
| | 62,838 |
| | 14,970 |
| | 7,500 |
| | 23,856 |
| | 10,547 |
| | 121,586 |
| 29,362 |
| | 63,634 |
| | 14,464 |
| | 6,946 |
| | 23,893 |
| | 5,384 |
| | 123,649 |
|
Average use per residential customer (kWh) | 13,642 |
| | 15,717 |
| | 15,210 |
| | 11,939 |
| | 15,503 |
| | — |
| | 14,831 |
| 12,933 |
| | 14,956 |
| | 15,013 |
| | 12,534 |
| | 15,035 |
| | — |
| | 14,316 |
|
| |
| (a) | Includes the effect of intercompany eliminations. |
The following table illustrates the Utility operating companies’ 20152016 combined electric sales volume as a percentage of total electric sales volume, and 20152016 combined electric revenues as a percentage of total 20152016 electric revenue, each by customer class.
| | | Customer Class | | % of Sales Volume | | % of Revenue | | % of Sales Volume | | % of Revenue |
| Residential | | 29.7 | | 37.8 | | 28.4 | | 37.1 |
| Commercial | | 24.1 | | 27.0 | | 23.6 | | 26.6 |
| Industrial (a) | | 36.5 | | 26.4 | | 37.0 | | 26.2 |
| Governmental | | 2.1 | | 2.4 | | 2.1 | | 2.4 |
| Wholesale/Other | | 7.6 | | 6.4 | | 8.9 | | 7.7 |
| |
| (a) | Major industrial customers are primarily in the chemical, petroleum refining and pulp and paperchemical industries. |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
See “Selected Financial Data” for each of the Utility operating companies for the detail of their sales by customer class for 2011-2015.2012-2016.
Selected 20152016 Natural Gas Sales Data
Entergy New Orleans and Entergy Louisiana provide both electric power and natural gas to retail customers. Entergy New Orleans and Entergy Louisiana sold 10,635,98210,102,437 and 7,082,2606,288,105 Mcf, respectively, of natural gas to retail customers in 2015.2016. In 2015,2016, 99% of Entergy Louisiana’s operating revenue was derived from the electric utility business, and only 1% from the natural gas distribution business. For Entergy New Orleans, 87%88% of operating revenue was derived from the electric utility business and 13%12% from the natural gas distribution business in 2015.2016.
Following is data concerning Entergy New Orleans’s 20152016 retail operating revenue sources.
| | Customer Class | | Electric Operating Revenue | | Natural Gas Revenue | | Electric Operating Revenue | | Natural Gas Operating Revenue |
| Residential | | 43% | | 49% | | 43% | | 48% |
| Commercial | | 38% | | 27% | | 38% | | 27% |
| Industrial | | 6% | | 8% | | 6% | | 7% |
| Governmental/Municipal | | 13% | | 16% | | 13% | | 18% |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Retail Rate Regulation
General (Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
Each Utility operating company regularly participates in retail rate proceedings. The status of material retail rate proceedings is described in Note 2 to the financial statements. Certain aspects of the Utility operating companies’ retail rate mechanisms are discussed below.
|
| | | | | | | | | | | |
| | | Rate base (in billions) | | Current authorized return on common equity | | Weighted average cost of capital (after-tax) | | Equity ratio | | Regulatory construct | |
| | | | | | | | | | | | |
| Entergy Arkansas | | $6.609 (a) | | 9.25% -10.25% | | 4.54% | | 30.91% | | - forward test year formula rate plan
- riders: MISO, capacity, Grand
Gulf, energy efficiency, fuel and
purchased power | |
| | | | | | | | | | | | |
| Entergy Louisiana (electric) | | $7.4 (b) | | 9.15% - 10.75% | | 7.75% | | 53.10% | | - formula rate plan
- riders/specific recovery: MISO,
capacity, fuel, Ninemile 6 and
Union outside of sharing | |
| | | | | | | | | | | | |
| Entergy Louisiana (gas) | | $0.055 (c) | | 9.45% - 10.45% | | 7.54% | | 51.63% | | - gas rate stabilization plan
- rider: gas infrastructure | |
| | | | | | | | | | | | |
| Entergy Mississippi | | $1.979 (d) | | 9.89% - 11.97% | | 7.96% | | 48.22% | | - formula rate plan with
forward-looking features
- riders: power management, Grand
Gulf, fuel, MISO, unit power cost,
storm damage, energy efficiency, ad
valorem tax adjustment
| |
| | | | | | | | | | | | |
| Entergy New Orleans (electric) | | $0.299 (e) | | 10.7% - 11.5% | | 8.58% | | 50.08% | | - rate case
- riders/specific recovery: fuel, capacity | |
| | | | | | | | | | | | |
| Entergy New Orleans (gas) | | $0.089 (f) | | 10.25% - 11.25% | | 8.40% | | 50.08% | | - rate case
- rider: purchased gas | |
| | | | | | | | | | | | |
| Entergy Texas | | $1.634 (g) | | 9.8% | | 8.22% | | 48.6% | | - rate case
- riders: fuel, distribution and transmission, RPCE payments and rate case expenses, among others | |
| | | | | | | | | | | | |
| System Energy | | $1.307 (h) | | 10.94% | | 8.92% | | 65% | | - monthly cost of service | |
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
| |
| (a) | Based on 2017 forward test year. |
| |
| (b) | Based on December 31, 2015 test year and excludes approximately $475 million first-year average rate base for Union. |
| |
| (c) | Based on September 30, 2015 test year. |
| |
| (d) | Based on 2016 forward test year. |
| |
| (e) | Based on December 31, 2011 test year and excludes approximately $228 million first-year average rate base for Union. |
| |
| (f) | Based on December 31, 2011 test year. |
| |
| (g) | Based on March 31, 2013 adjusted test year. |
| |
| (h) | Based on calculation as of December 31, 2016. |
Entergy Arkansas
Fuel and Purchased Power Cost Recovery
Entergy Arkansas’s rate schedules include an energy cost recovery rider to recover fuel and purchased power 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’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.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Arkansas’s storm restoration costs.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Entergy Louisiana
Fuel Recovery
Entergy Louisiana’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. See Note 2 to the financial statements for a discussion of proceedings related to audits of Entergy Louisiana’s fuel adjustment clause filings.
To help stabilize electricity costs, Entergy Louisiana received approval from the LPSC 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.
Entergy Louisiana’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 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 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 Louisiana’s filings to recover storm-related costs.
Entergy Mississippi
Fuel Recovery
Entergy Mississippi’s rate schedules include energy cost recovery riders to recover fuel and purchased power costs. The energy cost rate for each calendar year is redetermined annually and includes a true-up adjustment reflecting the over-recovery or under-recovery of the energy costs as of the 12-month period ended September 30. Entergy Mississippi’s fuel cost recoveries are subject to annual audits conducted pursuant to the authority of the MPSC.
Power Management Rider
In November 2005 the MPSC approved the purchase of the Attala power plant and recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Attala plant through the power management rider until resolution of its general rate case. In 2012 the MPSC approved the purchase of the Hinds power plant and recovery of the investment cost through Entergy Mississippi’s power management rider. Entergy Mississippi recovered the annual ownership costs of the Hinds plant through the power management rider until resolution of its general rate case. See Note 2 to the financial statements for a discussion of Entergy Mississippi’s 2014 general rate case. Included in the rate changes and revenue adjustments effective with February 2015 bills was the realignment of the annual ownership costs associated with the Attala plant and the Hinds plant from the power management rider to base rates.
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-
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
thirdone-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.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of proceedings regarding recovery of Entergy Mississippi’s storm-related costs.
Entergy New Orleans
Fuel Recovery
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. 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
To help stabilize gas costs, Entergy New Orleans seeks approval annually from the City Council to continue implementation of its natural gas hedging program consistent with the City Council’s stated policy objectives. The program uses financial instruments to hedge exposure to volatility in the wholesale price of natural gas purchased to serve Entergy New Orleans gas customers. Entergy New Orleans hedges up to 25% of actual gas sales made during the winter months.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Storm Cost Recovery
See Note 2 to the financial statements for a discussion of Entergy New Orleans’s efforts to recover storm-related costs.
Entergy Texas
Fuel Recovery
Entergy Texas’s rate schedules include a fixed fuel factor to recover fuel and purchased power costs, including interest, that are not included 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. The PUCT fuel cost proceedings are discussed in Note 2 to the financial statements.
Electric Industry Restructuring
In June 2009, a law was enacted in Texas that required 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 law, the PUCT may not approve a
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
transition to competition plan for Entergy Texas until the expiration of four years from the PUCT’s certification of Entergy Texas’s power region.
The law also contains provisions that allow Entergy Texas to 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.
The law further amended 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 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 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.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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. The PUCT determined that unrecovered costs that could be recovered through the rider 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. After additional negotiations, and ultimately the scheduling of a hearing to resolve remaining contested issues, the PUCT issued the order approving the competitive generation service rider in July 2013. Entergy Texas filed for rehearing of the PUCT’s July 2013 order, which the PUCT denied. Entergy Texas has since filed its appeal of that PUCT order to the Travis County District Court, which found in favor of the PUCT in an order issued in October 2014. In November 2014, Entergy Texas appealed the District Court’s order which moves the appeal to the Third Court of Appeals. Entergy Texas and opposing parties filed briefs and responses in the first quarter 2015. Oral argument was held in May 2015. In March 2016 the Court of Appeals upheld the District Court’s ruling favoring the PUCT. In May 2016, Entergy Texas filed with the Texas Supreme Court a petition for review of the Court of Appeals ruling. In January 2017, Entergy Texas filed its petitioner’s brief on the merits with the Texas Supreme Court. The appeal remains pending.
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 September 2019, unless otherwise extended by the Texas Legislature.
Franchises
Entergy Arkansas holds exclusive franchises to provide electric service in approximately 308 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 pursuant to the terms of the franchise agreement and applicable statutes.
Entergy Louisiana holds non-exclusive franchises to provide electric service in approximately 175 incorporated municipalities and in the unincorporated areas of approximately 59 parishes of Louisiana. Entergy Louisiana holds non-exclusive franchises to provide natural gas service to customers in the City of Baton Rouge and in East Baton Rouge Parish. Municipal franchise agreement terms range from 25 to 60 years while parish franchise terms range from 25 to 99 years.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
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.
Entergy New Orleans provides electric and gas service in the City of New Orleans pursuant to indeterminate permits set forth in city ordinances. These ordinances contain a continuing option for the City of New Orleans to purchase Entergy New 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 27 counties in eastern Texas, and holds non-exclusive franchises to provide electric service in approximately 68 incorporated municipalities. Entergy Texas typically obtains 25-year franchise agreements as existing agreements expire. Entergy Texas’s electric franchises expire during 2016-2058.2017-2058.
The business of System Energy is limited to wholesale power sales. It has no distribution franchises.
Part I Item 1
Entergy Corporation, Utility operating companies, and System Energy
Property and Other Generation Resources
Owned Generating Stations
The total capability of the generating stations owned and leased by the Utility operating companies and System Energy as of December 31, 2015,2016, is indicated below:
| | | | | Owned and Leased Capability MW(a) | | Owned and Leased Capability MW(a) |
| Company | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro | | Total | | Gas/Oil | | Nuclear | | Coal | | Hydro |
| Entergy Arkansas | | 4,696 |
| | 1,618 |
| | 1,809 |
| | 1,196 |
| | 73 |
| | 5,231 |
| | 2,143 |
| | 1,818 |
| | 1,196 |
| | 74 |
|
| Entergy Louisiana | | 8,494 |
| | 6,003 |
| | 2,128 |
| | 363 |
| | — |
| | 9,572 |
| | 7,081 |
| | 2,132 |
| | 359 |
| | — |
|
| Entergy Mississippi | | 3,536 |
| | 3,116 |
| | — |
| | 420 |
| | — |
| | 3,522 |
| | 3,102 |
| | — |
| | 420 |
| | — |
|
| Entergy New Orleans | | 782 |
| | 782 |
| | — |
| | — |
| | — |
| | 512 |
| | 512 |
| | — |
| | — |
| | — |
|
| Entergy Texas | | 2,541 |
| | 2,272 |
| | — |
| | 269 |
| | — |
| | 2,272 |
| | 2,007 |
| | — |
| | 265 |
| | — |
|
| System Energy | | 1,261 |
| | — |
| | 1,261 |
| | — |
| | — |
| | 1,272 |
| | — |
| | 1,272 |
| | — |
| | — |
|
| Total | | 21,310 |
| | 13,791 |
| | 5,198 |
| | 2,248 |
| | 73 |
| | 22,381 |
| | 14,845 |
| | 5,222 |
| | 2,240 |
| | 74 |
|
| |
| (a) | “Owned and Leased 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. |
Summer peak load for the Utility has averaged 21,60421,566 MW over the previous decade. The Utility operating companies, in aggregate, are projected to have approximately 200 MW more than their minimum capacity requirements needed to meet MISO Resource Adequacy for 2016.
The Utility operating companies’ 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, and the availability and price of power, the location of new load, the economy, environmental regulations, public policy goals, and the age and condition of Entergy’s existing infrastructure. The resource planning processes also considers Entergy Arkansas’s exit from the System Agreement on December 18, 2013, Entergy Mississippi’s exit from the System Agreement on November 7, 2015, as well as the termination of the System Agreement at the end of August 2016 for the remainder of the Utility operating companies.
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The Utility operating companies’ long-term resource strategy, the “Portfolio Transformation Strategy,” calls for the bulk of capacity needs to be met through long-term resources, whether owned or contracted. Over the past decade, the Portfolio Transformation Strategy has resulted in the addition of about 5,7006,800 MW of new long-term resources.resources and the deactivation of over 4,800 MW of legacy generation. As MISO market participants, the Utility operating companies also participate in MISO’s Day Ahead and Real Time Energy and Ancillary Services markets to economically dispatch generation and purchase energy to serve customers reliably and at the lowest reasonable cost.
Other Generation Resources
RFP Procurements
The Utility operating companies from time to time issue 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 RFPs issued by the Utility operating companies have sought resources needed to meet near-term MISO reliability requirements as well as longer-term requirements through a broad range of wholesale power products, including limited-term (1 to 3 years) and long-term contractual products and asset acquisitions. The RFP process has resulted in the selectionselections or acquisition of the following,acquisitions, including, among other things, in:things:
Entergy Louisiana’s June 2005 purchase of the 718 MW, gas-fired Perryville plant, of which 35% of the output is sold to Entergy Texas;
Entergy Arkansas’s September 2008 purchase of the 789 MW, combined-cycle, gas-fired Ouachita Generating Facility. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, owns one-third of the facility;
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Entergy Arkansas’s November 2012 purchase of the 620 MW, combined-cycle, gas-fired Hot Spring Energy facility;
Entergy Mississippi’s November 2012 purchase of the 450 MW, combined-cycle, gas-fired Hinds Energy facility; and
Entergy Louisiana’s construction of the 560 MW, combined-cycle, gas turbine Ninemile 6 generating facility at its existing Ninemile Point electric generating station. The facility reached commercial operation in December 2014.2014; and
Entergy Louisiana’s construction of the 980 MW, combined-cycle, gas turbine St. Charles generating facility at its existing Little Gypsy electric generating station. Entergy Louisiana received regulatory approval from the LPSC in November 2016 and the facility is scheduled to be in service by June 2019.
The selection of the St.Lake Charles Power Station and Montgomery County Power Station self-build projectprojects from the 2014 Amite South RFP issued on behalf of Entergy Louisiana isand the RFP issued on behalf of Entergy Texas, respectively, are currently going through the regulatory approval process and, subject to such approval, full notice to proceed is expected to be issued in Summer 2016.summer 2017 for the Lake Charles Power Station and summer 2018 for the Montgomery County Power Station. Commercial operation is estimated to occur by Summer 2019.mid-2020 for Lake Charles Power Station and mid-2021 for Montgomery County Power Station.
The RFP process has also resulted in the selection, or confirmation of the economic merits of, long-term purchased power agreements (PPAs), including, among others:
River Bend 30% life-of-unit PPA between Entergy Louisiana and Entergy New Orleans for 100 MW related to Entergy Louisiana’s unregulated portion of the River Bend nuclear station, which portion was formerly owned by Cajun;
Entergy Arkansas wholesale base load capacity life-of-unit PPAs 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’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
12-month agreements originally executed in 2005 and which are renewed annually between Entergy Arkansas and Entergy Louisiana and Entergy Texas, and between Entergy Arkansas and Entergy Mississippi, relating to the sale of a portion of Entergy Arkansas’s coal and nuclear base load resources (which had not been included in Entergy Arkansas’s retail rates);
In December 2009, Entergy Texas and Exelon Generation Company, LLC executed a 10-year agreement for 150-300 MW from the Frontier Generating Station located in Grimes County, Texas;
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In May 2011, Entergy Texas and Calpine Energy Services, L.P. executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. Entergy Louisiana purchases 50% of the facility’s capacity and energy from Entergy Texas;Texas. In July 2014, LS Power purchased the Carville Energy Center and replaced Calpine Energy Services as the counterparty to the agreement;
In September 2012, Entergy Gulf States Louisiana executed a 20-year agreement for 28 MW, with the potential to purchase an additional 9 megawattsMW when available, from Rain CII Carbon LLC’s pet coke calcining facility in Sulphur, Louisiana. The facility began commercial operation in May 2013. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with the facility.
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. Cost recovery for this agreement was approved within Entergy Arkansas’s general rate case filed in March 2013;facility;
In March 2013, Entergy Gulf States Louisiana executed a 20-year agreement for 8.5 MW from Agrilectric Power Partners, LP’s refurbished rice hull-fueled electric generation facility located in Lake Charles, Louisiana. Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, now holds the agreement with Agrilectric.Agrilectric;
In September 2013, Entergy Louisiana executed a 10-year agreement with TX LFG Energy, LP, a wholly-owned subsidiary of Montauk Energy Holdings, LLC, to purchase approximately 3 MW from its landfill gas-fueled power generation facility located in Cleveland, Texas.Texas;
Entergy Mississippi’s cost-based purchase, beginning in January 2013, of 90 MW from Entergy Arkansas’s share of Grand Gulf (only 60 MW of this PPA came through the RFP process). Cost recovery for the 90 MW was approved by the MPSC in January 2013; and
In April 2015, Entergy Arkansas and Stuttgart Solar, LLC executed a 20-year agreement for 81 MW from a solar photovoltaic electric generation facility located near Stuttgart, Arkansas. The APSC has approved the project, and the expected commercial operation date is in June 2019.2019; and
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In June 2015,November 2016, Entergy Services, on behalf ofLouisiana and LS Power executed a 10-year agreement for 485 MW from the Carville Energy Center located in St. Gabriel, Louisiana. The transaction is pending regulatory approval.
In May 2016, Entergy Texas,Arkansas issued the RFP for Long-Term Combined Cycle Turbine Capacity and Energy Resources and Limited-Term Capacity and EnergyRenewable Generation Resources. This RFP is seeking long-term resources up to 1,000100 MW beginning in June 2021 and limited termof renewable resources, up to 700 MW beginning as early as 2017June 2018, to help Entergy Arkansas meet transitional capacityits long-term generation resource needs and energy needs. This RFP includes a self-build option at Entergy Texas’s Lewis Creek site.increase the depth and breadth of generation supply within its generation resource portfolio.
In September 2015,June 2016, Entergy Services, on behalf of Entergy Louisiana, issued the RFP for Developmental and Existing Capacity and EnergyLong-Term Renewable Generation Resources. This RFP is seeking up to 1,000 MW for developmental and/or existing resources beginning in June 2020. This RFP includes a self-build option at Entergy Louisiana’s Nelson site.
In December 2015, Entergy Services, on behalf of Entergy Louisiana, issued notice of intent to issue a RFP for Renewable Resources. This RFP will seek up to 200 MW of renewable resources, to identify potentially cost-effective renewable resourcesbeginning as early as June 2018 and as late as June 1, 2020, that can provide energy, fuel diversity, and other benefits to customers.
In July 2016, Entergy Services, on behalf of Entergy New Orleans, issued the RFP for Long-Term Renewable Generation Resources. This RFP is seeking up to 20 MW of renewable resources beginning as early as June 2018 and as late as June 1, 2020 that can provide increased depth and diversity to its generation resource portfolio. This RFP includes a self-build option for an aggregated solar photovoltaic resource located within Orleans Parish, Louisiana.
Other Procurements From Third Parties
The Utility operating companies have also made resource acquisitions outside of the RFP process, including Entergy Mississippi’s January 2006 acquisition of the 480 MW, combined-cycle, gas-fired Attala power plant; Entergy Gulf States Louisiana’s March 2008 acquisition of the 322 MW, simple-cycle, gas-fired Calcasieu Generating Facility; and Entergy Louisiana’s April 2011 acquisition of the 580 MW, combined-cycle, gas-fired Acadia Energy Center Unit 2.2; and Entergy Arkansas’s (Power Block 2), Entergy Louisiana’s (Power Blocks 3 and 4), and Entergy New Orleans’s (Power Block 1) March 2016 acquisitions of the 1,980 MW (summer rating), natural gas-fired, combined-cycle gas turbine Union Power Station power blocks, each rated at 495 MW (summer rating). The Utility operating companies have also entered into various limited- and long-term contracts in recent years as a result of bilateral negotiations.
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the original agreement, Entergy Gulf States Louisiana will acquire two of the power blocks and a 50% undivided ownership interest
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in certain assets related to the facility, and Entergy Arkansas and Entergy Texas would each acquire one power block and a 25% undivided ownership interest in the related assets. Entergy Texas subsequently chose to withdraw its certification filing for the purchase of one of the power blocks at the Union Power Station. In July 2015 the PUCT approved Entergy Texas’s withdrawal. Following Entergy Texas’s withdrawal, the power block was reallocated to Entergy New Orleans. Additionally, the business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of two of the power blocks at the Union Power Station. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. These include regulatory approvals from the APSC, LPSC, CNO, and FERC, as well as clearance under the Hart-Scott-Rodino anti-trust law. As of early January 2016, each of the Entergy's Utility operating companies involved in the purchase agreement has received retail regulatory approvals from their respective retail regulator. Closing of the purchase is expected to be completed promptly following the receipt of FERC approval.
Interconnections
The Utility operating companies’ 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 provided dispatch instructions by MISO. Entergy’s Utility operating companies are MISO market participants and are interconnected with many neighboring utilities. MISO is an essential link in the safe, cost-effective delivery of electric power across all or parts of 15 U.S. states and the Canadian province of Manitoba. As a Regional Transmission Organization, MISO assures consumers of unbiased regional grid management and open access to the transmission facilities under MISO’s functional supervision. In addition, the Utility operating companies are members of the SERC Reliability Corporation (SERC). SERC is a nonprofit corporation responsible for promoting and improving the reliability, adequacy, and critical infrastructure of the bulk power supply systems in all or portions of 16 central and southeastern states. SERC serves as a regional entity with delegated authority from the North American Electric Reliability Corporation (NERC) for the purpose of proposing and enforcing reliability standards within the SERC Region.
Gas Property
As of December 31, 2015,2016, Entergy New Orleans distributed and transported natural gas for distribution within New Orleans, Louisiana, through approximately 2,500 miles of gas pipeline. As of December 31, 2015,2016, the gas properties of Entergy Louisiana, which are located in and around Baton Rouge, Louisiana, were not material to Entergy Louisiana’s financial position.
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Title
The Utility operating companies’ 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 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.
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Fuel Supply
The sources of generation and average fuel cost per kWh for the Utility operating companies and System Energy for the years 2013-20152014-2016 were:
| | | | | Natural Gas | | Nuclear | | Coal | | Purchased Power | | Natural Gas | | Nuclear | | Coal | | Purchased Power | | MISO Purchases |
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 | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh | | % of Gen | | Cents Per kWh |
| 2016 | | | 41 | | 2.44 |
| | 28 | | 0.63 |
| | 7 | | 2.65 |
| | 9 | | 3.71 |
| | 15 | | 3.13 |
|
| 2015 | | 35 | | 2.65 |
| | 31 | | 0.85 |
| | 7 | | 2.85 |
| | 27 | | 3.39 |
| | 35 | | 2.65 |
| | 31 | | 0.85 |
| | 7 | | 2.85 |
| | 11 | | 3.63 |
| | 16 | | 3.24 |
|
| 2014 | | 28 | | 4.36 |
| | 33 | | 0.89 |
| | 11 | | 2.63 |
| | 28 | | 5.14 |
| | 28 | | 4.36 |
| | 33 | | 0.89 |
| | 11 | | 2.63 |
| | 9 | | 6.16 |
| | 19 | | 4.63 |
|
| 2013 | | 26 | | 4.12 |
| | 39 | | 0.92 |
| | 10 | | 2.70 |
| | 25 | | 4.32 |
| |
Actual 20152016 and projected 20162017 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 | | Nuclear | | Coal | | Purchased Power | Natural Gas | | Nuclear | | Coal | | Purchased Power (d) | | MISO Purchases (e) |
| | 2015 | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 | | 2015 | | 2016 | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 |
| Entergy Arkansas (a) | 18 | % | | 30 | % | | 54 | % | | 51 | % | | 14 | % | | 18 | % | | 14 | % | | — | % | 27 | % | | 36 | % | | 50 | % | | 55 | % | | 15 | % | | 9 | % | | 2 | % | | — |
| | 6 | % | | — |
| Entergy Louisiana | 46 | % | | 47 | % | | 27 | % | | 28 | % | | 2 | % | | 3 | % | | 25 | % | | 22 | % | 47 | % | | 52 | % | | 28 | % | | 30 | % | | 3 | % | | 4 | % | | 7 | % | | 14 | % | | 15 | % | | — |
Entergy Mississippi | 39 | % | | 50 | % | | 27 | % | | 25 | % | | 8 | % | | 16 | % | | 26 | % | | 9 | % | 51 | % | | 59 | % | | 14 | % | | 35 | % | | 13 | % | | 6 | % | | — | % | | — |
| | 22 | % | | — |
Entergy New Orleans | 38 | % | | 53 | % | | 44 | % | | 35 | % | | — | % | | 2 | % | | 18 | % | | 10 | % | 45 | % | | 57 | % | | 29 | % | | 41 | % | | 2 | % | | 1 | % | | 3 | % | | 1 | % | | 21 | % | | — |
| Entergy Texas | 39 | % | | 25 | % | | 8 | % | | 16 | % | | 4 | % | | 7 | % | | 49 | % | | 52 | % | 37 | % | | 31 | % | | 9 | % | | 16 | % | | 5 | % | | 11 | % | | 36 | % | | 42 | % | | 13 | % | | — |
System Energy (b)(c) | — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| — |
| | — |
| | 100 | % | | 100 | % | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| Utility (a) | 35 | % | | 42 | % | | 31 | % | | 32 | % | | 7 | % | | 8 | % | | 27 | % | | 18 | % | |
| Utility (a) (b) | | 41 | % | | 42 | % | | 28 | % | | 42 | % | | 7 | % | | 6 | % | | 9 | % | | 10 | % | | 15 | % | | — |
| |
| (a) | Hydroelectric power provided less than 1% of Entergy Arkansas’s generation in 20152016 and is expected to provide about 1% of its generation in 2016.2017. |
| |
| (b) | Solar power is expected to provide less than 1% of each of Entergy Mississippi’s and Entergy New Orleans's generation in 2017. |
| |
| (c) | Capacity and energy from System Energy’s interest in Grand Gulf is allocated as 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 Louisiana, Entergy Mississippi, and Entergy New Orleans. |
| |
| (d) | Excludes MISO purchases. |
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| |
| (e) | In December 2013, Entergy integrated its transmission system into the MISO RTO. Entergy offers all of its generation into the MISO energy market on a day-ahead and real-time basis and bids for power in the MISO energy market to serve the demand of its customers. All MISO related purchases and sales transactions are recorded on a net hourly position and therefore the volume of MISO purchased power is not projected for 2017. |
Some of the Utility’s gas-fired plants are also capable of also using fuel oil, if necessary. In addition, two small peaking units burn only oil. AnyAlthough based on current economics the Utility does not expect fuel oil use in 2017, it is included inpossible that various operational events including weather or pipeline maintenance may require the total for gas.use of fuel oil.
Natural Gas
The Utility operating companies have long-term firm and short-term interruptible gas contracts for both supply and transportation. Long-term firm contracts for power plants comprise less than 25%Over 50% of the Utility operating companies’ total requirements.power plants maintain some level of long-term firm transportation. 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.
Many factors, including wellhead deliverability, storage, 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
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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 committed to five one- to three-year contracts that will supply approximately 85% of the total coal supply needs in 2016.2017. These contracts are staggered in term so that not all contracts have to be renewed the same year. The remaining 15% of total coal requirements will be satisfied by contracts with a term of less than one year. Based on continued improved Powder River Basin (PRB) coal deliveries by rail and the high cost of alternate sources and modes of transportation, no alternative coal consumption is expected at Entergy Arkansas during 2016.2017. Coal will be transported to Arkansas via an existing transportation agreement that is expected to provide all of Entergy Arkansas’s rail transportation requirements for 2016.2017.
Entergy Louisiana has committed to threefive one- to three-year contracts that will supply approximately all of Nelson Unit 6 coal needs in 2016.2017. If needed, additional PRB coal will be purchased through contracts with a term of less than one year to provide the remaining supply needs. For the same reasons as for Entergy Arkansas’s plants, no alternative coal consumption is expected at Nelson Unit 6 during 2016.2017. Coal will be transported to Nelson primarily via an existinga new transportation agreement that begins in 2017 and is expected to provide allthe majority of Entergy Louisiana’s rail transportation requirements for 2016.2017.
For the year 2015,2016, coal transportation delivery to Entergy Arkansas- and Entergy Louisiana-operated coal-fired units exceeded coal demand at the plantswas adequate and it is expected that delivery times experienced in 20152017 will continue to be adequateconsistent through 2016.2017. Both Entergy Arkansas and Entergy 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 Louisiana and Entergy Texas that it has adequate rail car and barge capacity to meet the volumes of PRB coal requested for 2016.2017. Entergy Louisiana’s and Entergy Texas’s coal nomination requests to Big Cajun 2 - Unit 3 are made on an annual basis.
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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.
The Registrant Subsidiaries that own nuclear plants, Entergy Arkansas, Entergy Louisiana, and System 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. 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 obligations of the pooled contracts are on a several but not joint basis. The shared regulated uranium pool maintains inventories of nuclear materials during the various stages of processing. The Registrant Subsidiaries purchase enriched uranium hexafluoride for their nuclear plant reload requirements at the average inventory cost from the shared regulated uranium pool. Entergy Operations, Inc. contracts separately for the fabrication of nuclear 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 DOE and the owner of a nuclear power plant.
Based upon currently planned fuel cycles, the nuclear units in both the Utility and Entergy Wholesale Commodities segments have a diversified portfolio of contracts and inventory that provides substantially adequate
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nuclear fuel materials and conversion and enrichment services at what Entergy believes are reasonably predictable or fixed prices through most of 20162017 or beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the pending sale of the FitzPatrick plant and the planned permanent shutdowns of the FitzPatrickPalisades, Pilgrim, Indian Point 2, and PilgrimIndian Point 3 plants. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners. There are a number of possible supply alternatives that may be accessed to mitigate any supplier performance failure, including potentially drawing upon Entergy’s inventory intended for later generation periods depending upon its risk management strategy at that time, although the pricing of any 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.
The effects of market price changes may be reduced and deferred by risk management strategies, such 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. 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’s ability to assure nuclear fuel supply also depends upon the performance reliability of conversion, enrichment, and fabrication services providers. There are fewer of these providers than for uranium. For conversion and enrichment services, like uranium, Entergy diversifies its supply by supplier and country and may take special measures as needed to ensure supply of enriched uranium for the reliable fabrication of nuclear fuel. For fabrication services, each plant is dependent upon the effective performance of the fabricator of that plant’s nuclear fuel, therefore, Entergy provides additional monitoring, inspection, and oversight for the fabrication process to assure reliability and quality.
Entergy Arkansas, 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
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the issuance of notes. These credit facilities are subject to periodic renewal, and the notes are issued periodically, typically for terms between three and tenseven years.
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 Louisiana purchased natural gas for resale in 2016 under a firm contract from Enbridge Marketing (U.S.) Inc. until September 1, 2015. Starting on September 1, 2015 the purchases were from Sequent Energy Management L.P. 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 Louisiana’s or Entergy New 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.
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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,of electricity rates and interstate transmission of electricity, as well as rates forincluding 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. See Note 2 to the financial statements for further discussion of federal regulation proceedings.
System Agreement (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
ThePrior to each operating company’s termination of participation in the System Agreement (Entergy Arkansas in December 2013, Entergy Mississippi in November 2015, and Entergy Louisiana, Entergy New Orleans, and Entergy Texas each in August 2016), 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 iswas a rate schedule that has been approved by the FERC. Under the terms of the System Agreement, generating capacity and other power resources arewere jointly operated by the Utility operating companies that arewere participating in the System Agreement. The System Agreement provides,provided, among other things, that parties having generating reserves greater than their allocated share of reserves (long companies) shallwould receive payments from those parties having generating reserves that arewere less than their allocated share of reserves (short companies). Such payments arewere at amounts sufficient to cover certain of the long 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, the rates used to compensate long companies arewere based on costs associated with the long 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 arewere required to pay the cost of fuel consumed in generating such energy plus a charge to cover other associated costs. Entergy Arkansas terminated its participation in the System Agreement in December 2013. Entergy Mississippi terminated its participation in the System Agreement in November 2015. The System Agreement will terminateterminated with respect to its remaining participants onin August 31, 2016.
See “Although the System Agreement” has terminated, certain of the Utility operating companies’ retail regulators are pursuing litigation involving the System Agreement at the FERC and in the “Rate, Cost-recovery, and Other Regulation - Federal Regulation” sectionfederal courts. The proceedings include
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Entergy Corporation, Utility operating companies, and Subsidiaries Management’s Financial Discussion and Analysis for additional discussionSystem Energy
challenges to the allocation of costs as defined by the System Agreement.Agreement and other matters. See Note 2 to the financial statements for discussion of legal proceedings at the FERC and in federal courts involving the System Agreement.
Transmission and MISO Markets
See “Entergy’s IntegrationOn December 19, 2013, the Utility operating companies integrated into the MISO Regional Transmission Organization”RTO. Although becoming a member of MISO does not affect the ownership by the Utility operating companies of their transmission facilities or the responsibility for maintaining those facilities, MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the “Rate, Cost-recovery,MISO region, including the Utility operating companies. MISO also exercises functional control of transmission planning and Other Regulation - Federal Regulation” sectioncongestion management and provides schedules and pricing for the commitment and dispatch of Entergy Corporationgeneration that is offered into MISO’s markets, as well as pricing for load that bids into the markets. The Utility operating companies sell capacity, energy, and Subsidiaries Management’s Financial Discussionancillary services on a bilateral basis to certain wholesale customers and Analysis.offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. Each Utility operating company has its own transmission pricing zone and a formula rate template (included as Attachment O to the MISO tariff) used to establish transmission rates within MISO. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by FERC.
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’s decision also affected other aspects of System Energy’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’s and Entergy Mississippi’s acceleration of Grand Gulf purchased power obligations ceased effective July 2001 and July 2003, respectively, as approved by the FERC. See Note 2 to the financial statements for discussion of a complaint filed with the FERC in January 2017 regarding System Energy’s return on equity.
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Unit Power Sales Agreement
The Unit Power Sales Agreement allocates capacity, energy, and the related costs from System 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. Payments under the Unit Power Sales Agreement are System Energy’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.
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’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’s retained share of Grand Gulf to those companies, with the remainder of the retained share being sold to Entergy Mississippi through a separate life-of-resources purchased power agreement. In a series of LPSC orders, court decisions, and agreements from late 1985 to mid-1988, Entergy Louisiana was granted rate relief with respect to costs associated with Entergy
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Louisiana’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’s approval. Entergy Arkansas also has a life-of-resources purchased power agreement with Entergy Mississippi to sell a portion of the output of Entergy Arkansas’s non-retained share of Grand Gulf. Entergy Mississippi was granted rate relief for those purchases by the MPSC through its annual unit power cost rate mechanism.
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’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’s total operating expenses for Grand Gulf (including depreciation at a specified rate and expenses incurred in a permanent shutdown of Grand Gulf) and interest charges. The September 1989 write-off of System Energy’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.
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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 one outstanding series of 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.”bonds. 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.
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 and, 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’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 a supplement as security for its one outstanding series of first mortgage bonds. The 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’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
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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’s indebtedness then outstanding who have received the assignments of the Capital Funds Agreement. No such consent would be required to terminate the Capital Funds Agreement or the supplement thereto at this time.
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, but also provides services to Entergy Wholesale Commodities. 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 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” basis, pursuant to cost allocation methodologies for these service agreements that were approved by the FERC.
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
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operating under the sole retail jurisdiction of the LPSC, Entergy Gulf States Louisiana. Entergy Texas 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 Louisiana, as successor in interest to Entergy Gulf States Louisiana, 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 Texas purchases from Entergy Louisiana pursuant to a life-of-unit purchased power agreement 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 purchased power agreement. Entergy Louisiana purchases a 57.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Texas, and Entergy Texas purchases a 42.5% share of capacity and energy from the gas-fired generating plants owned by Entergy Louisiana. The purchased power agreements associatedIn connection with the gas-fired generating plants will terminate when the unit(s) is/are removed from Entergy System dispatch. The dispatch and operationtermination of the generating plants did not change as a result of the jurisdictional separation. Under the terms of a settlement agreement related to System Agreement termination effective August 31, 2016, the purchased power agreements willthat were put in place for certain legacy units at the time of the jurisdictional separation were also terminateterminated at that time. See Note 2 to the financial statements for additional discussion of the purchased power agreements in “System Agreement - Utility Operating Company Notices of Termination of System Agreement Participation” in the “Rate, Cost-recovery, and Other Regulation - Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.agreements.
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana (Old Entergy Louisiana) and Entergy Gulf States Louisiana (Old Entergy Gulf States Louisiana) were combined into a single public utility. In order
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to effect the business combination, under the Texas Business Organizations Code (TXBOC), Old Entergy Louisiana allocated substantially all of its assets to a new subsidiary, Entergy Louisiana Power, LLC, a Texas limited liability company (New Entergy Louisiana), and New Entergy Louisiana assumed the liabilities of Old Entergy Louisiana, in a transaction regarded as a merger under the TXBOC. Under the TXBOC, Old Entergy Gulf States Louisiana allocated substantially all of its assets to a new subsidiary (New Entergy Gulf States Louisiana) and New Entergy Gulf States Louisiana assumed the liabilities of Old Entergy Gulf States Louisiana, in a transaction regarded as a merger under the TXBOC. New Entergy Gulf States Louisiana then merged into New Entergy Louisiana with New Entergy Louisiana surviving the merger. Thereupon, Old Entergy Louisiana changed its name from “Entergy Louisiana, LLC” to “EL Investment Company, LLC” and New Entergy Louisiana changed its name from “Entergy Louisiana Power, LLC” to “Entergy Louisiana, LLC” (Entergy Louisiana). With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Old Entergy Louisiana and Old Entergy Gulf States Louisiana. See Note 2 to the financial statements for additional discussion of the business combination.
Earnings Ratios of Registrant Subsidiaries
The Registrant 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, |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| Entergy Arkansas | 2.04 | | 3.08 | | 3.62 | | 3.79 | | 4.31 | 3.32 | | 2.04 | | 3.08 | | 3.62 | | 3.79 |
| Entergy Louisiana | 3.36 | | 3.44 | | 3.30 | | 2.61 | | 2.90 | 3.57 | | 3.36 | | 3.44 | | 3.30 | | 2.61 |
| Entergy Mississippi | 3.59 | | 3.23 | | 3.19 | | 2.79 | | 3.55 | 3.96 | | 3.59 | | 3.23 | | 3.19 | | 2.79 |
| Entergy New Orleans | 4.90 | | 3.55 | | 1.85 | | 2.91 | | 4.72 | 4.61 | | 4.90 | | 3.55 | | 1.85 | | 2.91 |
| Entergy Texas | 2.22 | | 2.39 | | 1.94 | | 1.76 | | 2.34 | 2.92 | | 2.22 | | 2.39 | | 1.94 | | 1.76 |
| System Energy | 4.53 | | 4.04 | | 5.66 | | 5.12 | | 3.85 | 5.39 | | 4.53 | | 4.04 | | 5.66 | | 5.12 |
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| | | | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, | Ratios of Earnings to Combined Fixed Charges and Preferred Dividends or Distributions Years Ended December 31, |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| Entergy Arkansas | 1.85 | | 2.76 | | 3.25 | | 3.36 | | 3.83 | 3.09 | | 1.85 | | 2.76 | | 3.25 | | 3.36 |
| Entergy Louisiana | 3.24 | | 3.28 | | 3.14 | | 2.47 | | 2.74 | 3.57 | | 3.24 | | 3.28 | | 3.14 | | 2.47 |
| Entergy Mississippi | 3.34 | | 3.00 | | 2.97 | | 2.59 | | 3.27 | 3.71 | | 3.34 | | 3.00 | | 2.97 | | 2.59 |
| Entergy New Orleans | 4.50 | | 3.26 | | 1.70 | | 2.63 | | 4.25 | 4.30 | | 4.50 | | 3.26 | | 1.70 | | 2.63 |
The Registrant Subsidiaries accrue interest expense related to unrecognized tax benefits in income tax expense and do not include it in fixed charges.
Entergy Wholesale Commodities
Entergy Wholesale Commodities includes the ownership, operation, and decommissioning of nuclear power plants, located in the northern United States and the sale of the electric power produced by its operating plants to wholesale customers. Entergy Wholesale Commodities revenues are primarily derived from sales of energy and generation capacity 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. Entergy Wholesale Commodities also includes the ownership of or participationinterests in joint ventures that own, non-nuclear power plants and the sale to wholesale customers ofthat sell the electric power produced by these plants.those plants to wholesale customers.
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On December 29, 2014, Entergy Wholesale Commodities’ Vermont Yankee plant was removed from the grid, after 42 years of operations. The decision to close and decommission Vermont Yankee was announced in August 2013, as a result of numerous issues including sustained low natural gas and wholesale energy prices, the high cost structure of the plant, and lack of a market structure that adequately compensates merchant nuclear plants for their environmental and fuel diversity benefits in the Northeast region. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, LLC to a subsidiary of NorthStar Group Services, Inc. (NorthStar). Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. The sale of Entergy Nuclear Vermont Yankee to NorthStar will include the transfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust fund and the asset retirement obligation for spent fuel management and decommissioning of the plant. Entergy plans to transfer all spent nuclear fuel to dry cask storage by the end of 2018, subject to obtaining necessary regulatory approvals, in advance of the planned transaction close. Under the sale agreement and related agreements to be entered into at the closing, NorthStar will commit to initiate decommissioning and site restoration by 2021 and complete those activities, along with the partial restoration of the Vermont Yankee site, with the exception of the independent spent fuel storage installation and the switchyard, by 2030. The original completion date, as outlined in Entergy’s Post Shutdown Decommissioning Activities Report filed with the NRC, was 2075. The transaction is contingent upon certain closing conditions, including approval by the NRC; approval by the State of Vermont Public Service Board, including approval of site restoration standards that will be proposed as part of the transaction; the transfer of all spent nuclear fuel to dry fuel storage on the independent spent fuel storage installation; and that the market value of the fund assets held in the decommissioning trust fund for the Vermont Yankee Nuclear Power Station, less the hypothetical income tax on the aggregate unrealized net gain of such fund assets at closing, is equal to or exceeds $451.95 million, subject to adjustments.
In October 2015, Entergy determined that it willwould close the FitzPatrick plant earlier than expected. The original expectation was to shut down the FitzPatrick plant at the end of the currentits fuel cycle planned forin January 27, 2017, because of poor market conditions that have ledbut in August 2016, Entergy entered into an agreement to decreased revenues, a poor market design that failssell the FitzPatrick plant to properly compensate nuclear generators forExelon, and the benefits they provide, and increased operational costs. The decision came after management’s extensive analysis of whether it was advisable economicallysale is expected to refuel the plant as scheduledclose in the fallfirst half of 2016.2017. The transaction is contingent upon, among other things, the expiration of the applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, the receipt of necessary regulatory approvals from the FERC, the NRC, and the Public Service Commission of the State of New York (NYPSC), and the receipt of a private letter ruling from the IRS. NRC approval has not yet been received, but all other necessary regulatory approvals have been received. Because certain specified conditions were satisfied in November 2016,
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including the continued effectiveness of the Clean Energy Standards/Zero Emissions Credit program (CES/ZEC), the establishment of certain long-term agreements on acceptable terms with the Energy Research and Development Authority of the State of New York in connection with the CES/ZEC program, and NYPSC approval of the transaction on acceptable terms, Entergy refueled the FitzPatrick plant in January and February 2017.
In October 2015, Entergy determined that it willwould close the Pilgrim plant no later than June 1, 2019 because of poor market conditions that have led to reduced revenues, a poor market design that fails to properly compensate nuclear generators for the benefits they provide, and increased operational costs.plant. The decision came after management’s extensive analysis of the economics and operating life of the plant following the NRC’s decision in September 2015 to place the plant in Column 4its “multiple/repetitive degraded cornerstone column” (Column 4) of theits Reactor Oversight Process Action Matrix. The Pilgrim plant is expected to cease operations on May 31, 2019, after refueling in the spring of 2017 and operating through the end of that fuel cycle.
In December 2015, Entergy Wholesale Commodities closed on the sale of its 583 MW Rhode Island State Energy Center (RISEC), in Johnston, Rhode Island. The base sales price, excluding adjustments, was approximately $490 million. Entergy Wholesale Commodities purchased RISEC for $346 million in December 2011.
In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Pursuant to the PPA termination agreement, Consumers Energy will pay Entergy $172 million for the early termination of the PPA. The sale was consistentPPA termination agreement is subject to regulatory approvals. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through October 1, 2018.
In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. As part of the settlement, New York State has agreed to issue Indian Point’s water quality certification and Coastal Zone Management Act consistency certification and to withdraw its objection to license renewal before the NRC. New York State also has agreed to issue a water discharge permit, which is required regardless of whether the plant is seeking a renewed NRC license. The shutdowns are conditioned, among other things, upon such actions being taken by New York State. Even without opposition, the NRC license renewal process is expected to continue at least into 2018.
With the settlement concerning Indian Point, Entergy now has announced plans for the disposition of all of the Entergy Wholesale Commodities’ strategyCommodities nuclear power plants, including the sales of freeing financial resourcesVermont Yankee and risk reductionFitzPatrick, and the earlier than previously expected shutdowns of its portfolio.Pilgrim, Palisades, Indian Point 2, and Indian Point 3. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” for further discussion.
Property
Nuclear Generating Stations
Entergy Wholesale Commodities includes the ownership of the following nuclear power plants:
|
| | | | | | | | | | | | |
Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity- Reactor Type | | License Expiration Date |
| Pilgrim (a) | | IS0-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 (a) |
| FitzPatrick (b) | | NYISO | | 1975 | | Nov. 2000 | | Oswego, NY | | 838 MW - Boiling Water | | 2034 (b) |
| Indian Point 3 | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 (d) |
| Indian Point 2 | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (d) |
| Vermont Yankee (c) | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 (c) |
| Palisades | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 |
|
| | | | | | | | | | | | |
| Power Plant | | Market | | In Service Year | | Acquired | | Location | | Capacity - Reactor Type | | License Expiration Date |
| Pilgrim (a) | | IS0-NE | | 1972 | | July 1999 | | Plymouth, MA | | 688 MW - Boiling Water | | 2032 (a) |
| FitzPatrick (b) | | NYISO | | 1975 | | Nov. 2000 | | Oswego, NY | | 838 MW - Boiling Water | | 2034 (b) |
| Indian Point 3 (c) | | NYISO | | 1976 | | Nov. 2000 | | Buchanan, NY | | 1,041 MW - Pressurized Water | | 2015 (c) |
| Indian Point 2 (c) | | NYISO | | 1974 | | Sept. 2001 | | Buchanan, NY | | 1,028 MW - Pressurized Water | | 2013 (c) |
| Vermont Yankee (d) | | IS0-NE | | 1972 | | July 2002 | | Vernon, VT | | 605 MW - Boiling Water | | 2032 (d) |
| Palisades (e) | | MISO | | 1971 | | Apr. 2007 | | Covert, MI | | 811 MW - Pressurized Water | | 2031 (e) |
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| (a) | In October 2015, Entergy determined that it willwould close the Pilgrim plant no later than June 1, 2019, as discussed above. |
| |
| (b) | In October 2015, Entergy determined that it willwould close the FitzPatrick plant at the end of the current fuel cycle, whichin January 2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon, and the sale is planned for January 27,expected to close in the first half of 2017. |
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| (c) | On December 29, 2014, the Vermont Yankee plant ceased power production. |
| |
(d) | In January 2017, Entergy announced that it reached a settlement with New York State to shut down Indian Point 2 by April 30, 2020 and Indian Point 3 by April 30, 2021, and resolve all New York State-initiated legal challenges to Indian Point’s operating license renewal. See below for discussion of Indian Point 2 and Indian Point 3 entering their “period of extended operation” after expiration of the plants’ initial license terms under “timely renewal.” |
| |
| (d) | On December 29, 2014, the Vermont Yankee plant ceased power production. In November 2016, Entergy entered into an agreement to sell 100% of the membership interest in Entergy Nuclear Vermont Yankee, to NorthStar. Entergy Nuclear Vermont Yankee is the owner of the Vermont Yankee plant. |
| |
| (e) | In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. Separately, and assuming regulatory approvals are obtained for the PPA termination agreement, Entergy intends to shut down the Palisades nuclear power plant permanently on October 1, 2018, after refueling in the spring of 2017 and operating through the end of that fuel cycle. |
Entergy Wholesale Commodities also includes the ownership of two non-operating nuclear facilities, Big Rock Point in Michigan and Indian Point 1 in New York that were acquired when Entergy purchased the Palisades and Indian Point 2 nuclear plants, respectively. These facilities are in various stages of the decommissioning process.
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In April 2007, Entergy submitted to the NRC a joint application to renew the operating licenses for Indian Point 2 and Indian Point 3 for an additional 20 years. The original expiration dates of the NRC operating licenses for Indian Point 2 and Indian Point 3 were September 28, 2013 and December 12, 2015, respectively. Authorization to operate Indian Point 2 and Indian Point 3 rests on Entergy’s having timely filed a license renewal application that remains pending before the NRC. Indian Point 2 and Indian Point 3 have now entered their “period of extended operation” after expiration of the plants’ initial license term under “timely renewal,” which is a federal statutory rule of general applicability providing for extension of a license for which a renewal application has been timely filed with the licensing agency until the license renewal process has been completed. The license renewal application for Indian Point 2 and Indian Point 3 qualifies for timely renewal protection because it met NRC regulatory standards for timely filing. For additional discussion of the license renewal applications and the settlement with New York State, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Non-nuclear Generating Stations
In November 2016, Entergy sold its 50% membership interest in Top Deer Wind Ventures, LLC, a wind-powered electric generation joint venture owned in the Entergy Wholesale Commodities segment and accounted for as an equity method investment. Entergy sold its 50% membership interest in Top Deer for $0.5 million and realized a pre-tax loss of $0.2 million.
Entergy Wholesale Commodities includes the ownership, or interests in joint ventures that own, the following non-nuclear power plants:
|
| | | | | | | | |
Plant | | Location | | Ownership | | Net Owned Capacity(a)
Capacity (a) | | Type |
| Independence Unit 2; 842 MW | | Newark, AR | | 14% | | 121 MW(b) | | Coal |
Top of Iowa; 80 MW (c) | | Worth County, IA | | 50% | | 40 MW | | Wind |
White Deer; 80 MW (c) | | Amarillo, TX | | 50% | | 40 MW | | Wind |
| RS Cogen; 425 MW (c) | | Lake Charles, LA | | 50% | | 213 MW | | Gas/Steam |
| Nelson 6; 550 MW | | Westlake, LA | | 11% | | 60 MW(b) | | Coal |
| |
| (a) | “Net Owned Capacity” refers to the nameplate rating on the generating unit. |
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| (b) | 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. |
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| (c) | Indirectly owned through interests in unconsolidated joint ventures. |
Independent System Operators
The Pilgrim plant falls 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 MISO. The primary purpose of ISO New England, NYISO, and MISO is to direct the operations of the major generation and transmission facilities in their respective regions; ensure grid reliability; administer and monitor wholesale electricity markets; and plan for their respective region’s energy needs.
Energy and Capacity Sales
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 also 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 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 Entergy Wholesale Commodities to deliver MWh of energy, make capacity available,
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or both. See “Market and Credit Risk Sensitive Instruments” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for additional information regarding these contracts.
As part of the purchase of the Palisades plant in 2007, Entergy executed a 15-year PPA with the seller, Consumers Energy, for 100% of the plant’s output, excluding any future uprates. Under the purchased power agreement, Consumers Energy receives the value of any new environmental credits for the first ten years of the agreement. Palisades 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” credit, etc.) or otherwise to have a market value. In December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. See discussion above for additional details regarding the agreement.
Customers
Entergy 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 and Consumers Energy, companies from which Entergy purchased plants, and ISO New England, NYISO, and MISO. Substantially all of the credit exposure associated with the planned energy output under contract for Entergy Wholesale Commodities nuclear plants is with counterparties or their guarantors that have public investment grade credit ratings.
Competition
The ISO New England and NYISO markets are highly competitive. Entergy Wholesale Commodities has numerous competitors in New England and 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. Entergy Wholesale Commodities is an independent power producer, which means it
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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. MISO does not have a centralized clearing capacity market, but load serving entities do meet the majority of their capacity needs through bilateral contracts and self-supply with a smaller portion coming through voluntary MISO auctions. The majority of Palisades’ current output is contracted to Consumers Energy through 2022, and, therefore,but in December 2016, Entergy announced that it reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant on May 31, 2018. Entergy expects to enter into a new PPA with Consumers Energy under which the plant would continue to operate through the planned shutdown date of October 1, 2018. See discussion above for additional details regarding the PPA termination agreement. Entergy Wholesale Commodities does not expect to be materially affected by competition in the MISO market in the near term.
Seasonality
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.
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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 Entergy 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.plant owners.
Other Business Activities
Entergy Nuclear Power Marketing, LLC (ENPM) was formed in 2005 to centralize the power marketing function for Entergy Wholesale Commodities nuclear plants. Upon its formation, ENPM entered into long-term power purchase agreements with the Entergy Wholesale Commodities subsidiaries that own nuclear 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’s functions include origination of new energy and capacity transactions and generation scheduling.
Entergy Nuclear, Inc. pursuescan pursue service agreements with other nuclear power plant owners who seek the advantages of Entergy’s scale and expertise but do not necessarily want to sell their assets. Services provided by either Entergy Nuclear, Inc. or other Entergy 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 plantplant.
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TLG Services, a subsidiary of Entergy Nuclear, Inc., offers decommissioning, engineering, and related services to nuclear power plant owners.
In 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 in November 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.
Regulation of Entergy’s Business
Federal Power Act
The Federal Power Act provides the FERC the authority to regulate:
the transmission and wholesale sale of electric energy in interstate commerce;
sale or acquisition of certain assets;
securities issuances;
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 Louisiana. The FERC also regulates the provisions of the System Agreement, including the rates, and the provision of transmission service to wholesale market participants. The FERC also regulates the MISO RTO, an independent entity that maintains functional control over the combined transmission systems of its members and administers wholesale energy, capacity, and ancillary services markets for market participants in the MISO region, including the Utility operating companies. FERC regulation of the MISO RTO includes regulation of the design and implementation of the wholesale markets administered by the MISO RTO, as well as the rates, terms, and conditions of open access transmission service over the member systems and the allocation of costs associated with transmission upgrades.
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;
set retail rates;
determine reasonable and adequate service;
control leasing;
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
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regulate the issuance and sale of certain securities.
Additionally, 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 APSC for consideration by the Tennessee Regulatory Authority. Additionally, Entergy Arkansas 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 retail rate or regulatory scheme in Missouri.
Entergy Louisiana’s electric and gas business is subject to regulation by the LPSC as to:
utility service;
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;
utility mergers and acquisitions and other changes of control; and
depreciation and other matters.
Prior to the transfer of the Algiers assets to Entergy New Orleans on September 1, 2015, Entergy Louisiana was 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 differed from that of the LPSC.
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Entergy Mississippi is subject to regulation by the MPSC as to the following:
utility service;
service areas;
facilities;
certification of generating facilities and certain transmission projects;
retail rates;
fuel cost recovery;
depreciation rates; and
mergers and changes of control.
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:
utility service;
retail rates and charges;
standards of service;
depreciation;
issuance and sale of certain securities; and
other matters.
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:
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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 and generation 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 Louisiana, and System Energy, as owners of all or portions of ANO, River Bend and 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 subsidiaries in the Entergy Wholesale Commodities segment are subject to the NRC’s jurisdiction as the owners and operatoroperators of Pilgrim, Indian Point Energy Center, FitzPatrick, Vermont Yankee, and Palisades. Substantial capital expenditures, increased operating expenses, and/or higher decommissioning costs at Entergy’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’s nuclear owner/licensee subsidiaries have been charged fees 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, 20152016 of $181.4$181.9 million for the one-time fee. Entergy accepted assignment of the Pilgrim, FitzPatrick and Indian Point 3, Indian Point 1 and Indian Point 2, Vermont Yankee, Palisades, and 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’s total spent fuel fees to date, including the one-time fee liability of Entergy Arkansas, have surpassed $1.6 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 current Presidential administration hasSpecific steps were taken specific steps to discontinue the Yucca Mountain project, and study a new spent fuel strategy. Such actions includedincluding 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. In August 2013 the U.S. Court of Appeals for the D.C. Circuit ordered the NRC to continue with the Yucca Mountain license review, but only to the extent of funds previously appropriated by Congress for that purpose and not yet used. This amount of money is not expected to be sufficient to complete the review. The government
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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.
Following the current Presidential administration’s defunding of the Yucca Mountain spent fuel repository program, the National Association of Regulatory Utility Commissioners and others sued the government seeking cessation of collection of the one mill per net kWh generated and sold after April 7, 1983 fee. In November 2013 the D.C. Circuit Court of Appeals ordered the DOE to submit a proposal to Congress to reset the fee to zero until the DOE complies with the Nuclear Waste Policy Act or Congress enacts an alternative waste disposal plan. In January 2014 the DOE submitted the proposal to Congress under protest, and also filed a petition for rehearing with the D.C. Circuit. The petition for rehearing was denied. The zero spent fuel fee went into effect prospectively in May 2014. Management cannot predict the potential timing or magnitude of future spent fuel fee revisions that may occur.
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 theseThese subsidiaries except for the owner of Palisades, beganhave been, and continue to be, involved in litigation to recover the damages caused by the DOE’s delay in performance. Through 2015,2016, Entergy’s subsidiaries won and collected on judgments in excess of $220totaling over $500 million. First round or second round damages cases are in progress covering each of the nuclear plants owned by Entergy subsidiaries.
In April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $29 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case. Also in April 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $44 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case. In June 2015, Entergy Arkansas and System Energy appealed to the U.S. Court of Appeals for the Federal Circuit portions of those decisions relating to cask loading costs. In April 2016 the Federal Circuit issued a decision in both appeals in favor of Entergy Arkansas and System Energy, and remanded the cases back to the U.S. Court of Federal Claims. In June 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $49 million in favor of System Energy and against the DOE in the second round Grand Gulf damages case, and Entergy received the payment from the U.S. Treasury in August 2016. In July 2016 the U.S. Court of Federal Claims issued a final judgment in the amount of $31 million in favor of Entergy Arkansas and against the DOE in the second round ANO damages case, and Entergy received payment from the U.S. Treasury in October 2016.
In May 2015, the U.S. Court of Federal Claims issued a final partial summary judgment on a portion, $21 million, of the claims in the Palisades case. The DOE did not appeal that decision, and Entergy received the payment from the U.S. Treasury in October 2015.
In December 2015 the U.S. Court of Federal Claims issued a judgment in the amount of $81 million in favor of Entergy Nuclear Indian Point 3 and Entergy Nuclear FitzPatrick in the first round Indian Point 3/FitzPatrick damages case, and Entergy received the payment from the U.S. Treasury in June 2016.
In January 2016 the U.S. Court of Federal Claims issued a judgment in the amount of $49 million in favor of Entergy Louisiana and against the DOE in the first round Waterford 3 damages case. In April 2016, Entergy Louisiana appealed to the U.S. Court of Appeals for the Federal Circuit the portion of that decision relating to cask loading costs. After the ANO and Grand Gulf appeal was rendered, the U.S. Court of Appeals for the Federal Circuit remanded the Waterford 3 case back to the U.S. Court of Federal Claims for decision in accordance with the U.S. Court of Appeals ruling on cask loading costs. In August 2016 the U.S. Court of Federal Claims issued a final judgment in the Waterford 3 case in the amount of $53 million, and Entergy Louisiana received payment from the U.S. Treasury in November 2016.
In April 2016 the U.S. Court of Federal Claims issued a partial judgment in the amount of $42 million in favor of Entergy Louisiana and against the DOE in the first round River Bend damages case, reserving the issue of cask loading costs pending resolution of the appeal on the same issues in the Entergy Arkansas and System Energy cases.
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Entergy Louisiana received payment from the U.S. Treasury in August 2016. In September 2016 the U.S. Court of Federal Claims issued a further judgment in favor of Entergy Arkansas and against the DOE in the second round ANO damagesRiver Bend case in the amount of $29.4$5 million. AlsoEntergy Louisiana received payment from the U.S. Treasury in April 2015January 2017.
In May 2016, Entergy Nuclear Vermont Yankee and the DOE entered into a stipulated agreement and the U.S. Court of Federal Claims issued a judgment in the amount of $19 million in favor of System EnergyEntergy Nuclear Vermont Yankee and against the DOE in the second round Grand GulfVermont Yankee damages case in the amount of $44.4 million. In June 2015,case. Entergy Arkansas and System Energy appealed portions of those decisions to the U.S. Court of Appeals for the Federal Circuit. The appeals remain pending. In May 2015, the U.S. Court of Federal Claims issued final partial summary judgment on a portion, $20.6 million, of the claims in the Palisades case. The DOE did not appeal that decision. A request forreceived payment from the U.S. Treasury was made in September 2015, and Entergy received the payment in October 2015. June 2016.
In December 2015 a final judgment in Entergy’s favor was rendered by the U.S. Court of Federal Claims in the Indian Point 3/FitzPatrick case in the amount of $80.9 million, but Entergy has moved for reconsideration on a portion of the disallowed costs. Although a trial has been held in the first round River Bend case, no decision has been issued. In JanuarySeptember 2016 the U.S. Court of Federal Claims issued a judgment in favor ofthe Entergy Louisiana and against the DOE in the first round Waterford 3 damagesNuclear Palisades case in the amount of $49.4$14 million. Entergy Nuclear Palisades received payment from the U.S. Treasury in January 2017.
In October 2016 the U.S. Supreme Court of Federal Claims issued a judgment in the second round Entergy
Nuclear Indian Point 2 case in the amount of $34 million. Entergy Nuclear Indian Point 2 received payment from the U.S. Treasury in January 2017.
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, at Indian Point and Vermont Yankee in 2008, at Waterford 3 in 2011, and at Pilgrim in 2015. These facilities will be expanded as needed.
Nuclear Plant Decommissioning
Entergy Arkansas, Entergy Louisiana, Entergy Texas, and System Energy are entitled to recover from customers through electric rates the estimated decommissioning costs for ANO, Waterford 3, and Grand Gulf, respectively. In addition, Entergy Louisiana and Entergy Texas are entitled to recover from customers through electric rates the estimated decommissioning costs for the portion of River Bend subject to retail rate regulation and Waterford 3, and Grand Gulf, respectively.regulation. The 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 July 2010 the LPSC approved increased decommissioning collections for Waterford 3 and the Louisiana regulated share of River Bend and in December 2010 the PUCT approved increased decommissioning collections for the Texas share of River Bend to address previously identified funding shortfalls. In December 2015 the APSC approved increased decommissioning collections for ANO 2 to address an identified shortfall. In December 2016 the APSC ordered continued collections for decommissioning for ANO 2, while finding that ANO 1’s decommissioning was adequately funded without continued collections. Entergy currently believes its decommissioning funding will be sufficient for its nuclear plants subject to retail rate regulation, although decommissioning cost inflation and trust fund performance will ultimately determine the adequacy of the funding amounts.
Following a reviewIn November 2016, Entergy entered into an agreement to sell 100% of the membership interest in 2009, Entergy concluded that there was a funding shortfall forNuclear Vermont Yankee to a subsidiary of approximately $40 million, which it satisfied with a $40 million guarantee from Entergy Corporation. Based on a revised financial assurance plan forNorthStar. Upon closing of the sale, NorthStar will assume ownership of Vermont Yankee notice of cancellation ofand its decommissioning and site restoration trusts, together with complete responsibility for the $40 million guarantee was providedfacility’s decommissioning and site restoration. The sale is subject to certain closing conditions, including approval from the NRC in December 2014, and in April 2015 the NRC provided a safety analysis report stating it had no objection to the cancellation, and the guarantee has subsequently been canceled.State of Vermont Public Service Board. See Note 19 to the financial statements for further discussion of Vermont Yankee decommissioning costs.costs and see “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the NorthStar transaction.
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For the Indian Point 3 and FitzPatrick plants purchased in 2000 from NYPA, NYPA retained the decommissioning truststrust funds and the decommissioning liabilities. NYPA and Entergy subsidiaries executed decommissioning agreements, which specify their decommissioning obligations. NYPA hasliabilities with the right to require the Entergy subsidiaries to assume each of the decommissioning liabilities provided that it assigns the corresponding decommissioning trust, up to a specified level, to the Entergy subsidiaries. IfIn August 2016, Entergy entered into a trust transfer agreement with NYPA to transfer the decommissioning trust funds and decommissioning liabilities are retainedfor the Indian Point 3 and FitzPatrick plants to Entergy. The transaction was contingent upon receiving approval from the NRC, which was received in January 2017. The decommissioning trust funds for the Indian Point 3 and FitzPatrick plants were transferred to Entergy by NYPA in January 2017. In August 2016, Entergy also entered into an agreement to sell the responsible Entergy subsidiary will performFitzPatrick plant to Exelon. Upon the closing of that sale, the FitzPatrick decommissioning trust along with the decommissioning obligation for that plant will be transfered to Exelon. See “Entergy Wholesale Commodities Exit from the Merchant Power Business” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion of the plants at a price equal to the lesser of a pre-specified level or the amount in the decommissioning trusts.Exelon transaction.
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In March 2015,2016 filings with the NRC were made for allcertain Entergy subsidiaries’ nuclear plants reporting on decommissioning funding. Those reports showed that decommissioning funding for each of those nuclear plants met the NRC’s financial assurance requirements.
Additional information with respect to Entergy’s decommissioning costs and decommissioning trust funds is found in Note 9 and Note 1716 to the financial statements.
Price-Anderson Act
The Price-Anderson Act requires that reactor licensees purchase and maintain the maximum amount of nuclear liability insurance available and participate in an industry assessment program called Secondary Financial Protection in order to protect 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 the contingent liability for a single nuclear incident to a maximum assessment of approximately $127.318$127.3 million per reactor (with 103102 nuclear industry reactors currently participating). In the case of a nuclear event in which Entergy Arkansas, Entergy Louisiana, System Energy, or an Entergy Wholesale Commodities company is liable, protection is afforded through a combination of private insurance and the Secondary Financial Protection program. In addition to this, insurance for property damage, costs of replacement power, and other risks relating to nuclear generating units is also purchased. 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.
NRC Reactor Oversight Process
The NRC’s Reactor Oversight Process is a program to collect information about plant performance, assess the information for its safety significance, and provide for appropriate licensee and NRC response. The NRC evaluates plant performance by analyzing two distinct inputs: inspection findings resulting from the NRC’s inspection program and performance indicators reported by the licensee. The evaluations result in the placement of each plant in one of the NRC’s Reactor Oversight Process Action Matrix columns: “licensee response column,” or Column 1, “regulatory response column,” or Column 2, “degraded cornerstone column,” or Column 3, and “multiple/repetitive degraded cornerstone column,” or Column 4. Plants in Column 1 are subject to normal NRC inspection activities. Plants in Column 2, Column 3, or Column 4 are subject to progressively increasing levels of inspection by the NRC with, in general, progressively increasing levels of associated costs. Waterford 3, Grand Gulf,River Bend, FitzPatrick, Indian Point 2, Indian Point 3, and Palisades are in Column 1. River BendGrand Gulf is in Column 2. Arkansas Nuclear One UnitsANO 1 and 2 are in Column 4, and are subject to an extensive set of required NRC inspections. Pilgrim is also in Column 4 and is subject to an extensive, but limited, set of required NRC inspections. See Note 8 to the financial statements for further discussion of the placement of Arkansas Nuclear OneANO 1 and 2, and Pilgrim in Column 4 of the NRC’s matrix.
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Environmental Regulation
Entergy’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’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’s businesses and is not expected to have a material 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 amendments establish several programs that currently or in the future may affect Entergy’s fossil-fueled generation facilities and, to a 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, greenhouse gases, and significant modifications to existing facilities;
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| • | Acid rain program for control of sulfur dioxide (SO2) and nitrogen oxides (NOx); |
Nonattainment area programs for control of criteria air 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 programs;
Interstate Air Transport;
Operating permitspermit program for administration and enforcement of these and other Clean Air Act programs;
Regional Haze and Best Available Retrofit Technology programs; and
New and existing source standards for greenhouse gas emissions.
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 certain non-routine modifications 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 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 for which the unit did not obtain a modified permit. Various courts and the EPA have been inconsistent in their judgments regarding modifications that are considered routine and on other legal issues that effectaffect this program.
In February 2011, Entergy received a request from the EPA 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, including New Source Review requirements and air permits issued by the Arkansas Department of Environmental Quality. In August 2011, Entergy’s Nelson facility, located in Louisiana, received a similar request for information from the EPA. In September 2015 a subsequent request for similar information was received for the White Bluff facility. Entergy responded or is in the process of responding to all requests. None of these EPA requests for information alleged that the facilities arewere in violation of 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 and availability of natural gas, incremental emission allowance costs, and the availability and cost of purchased power.
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Ozone Nonattainment
Entergy Texas operates one fossil-fueled generating unit (Lewis Creek) in a geographic area that is not in attainment of the currently-enforced national ambient air quality standards (NAAQS) for ozone. The nonattainment area that affects Entergy Texas is the Houston-Galveston-Brazoria area. Areas in nonattainment are classified as “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.
The Houston-Galveston-Brazoria area was originally classified as “moderate” nonattainment under the 1997 8-hour ozone standard with an attainment date of June 15, 2010. In June 2007 the Texas governor petitioned the EPA to reclassify Houston-Galveston-Brazoria from “moderate” to “severe” and the EPA granted the request in October 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 February 2015 the Texas Commission on Environmental Quality (TCEQ) submitted a request to EPA for a finding, and in December 2015, the EPA issued the finding that the Houston-Galveston-Brazoria area is in attainment with the 1997 8-hour ozone standard. In April 2015 the EPA revoked the 1997 ozone NAAQS and in May 2016, the EPA issued a proposed rule approving a substitute for the Houston-Galveston-Brazoria area. This redesignation indicates that the area has attained the revoked 1997 8-hour ozone NAAQS due to permanent and enforceable emission reductions and that it will maintain that NAAQS for 10 years from the date of the approval. Final approval will result in the area no longer being subject to any remaining anti-backsliding or non-attainment new source review requirements associated with the revoked 1997 NAAQS.
In March 2008 the EPA revised the NAAQS for ozone, creating the potential for additional counties and parishes in which Entergy operates to be placed in nonattainment status. In April 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 in “marginal” nonattainment. In August 2015 and January 2016, the EPA proposed determinations that the Baton Rouge and Memphis areas had attained the 2008 standard. These finalIn May 2016 the EPA finalized those determinations are pending.and extended the Houston-Galveston-Brazoria area’s attainment date for the 2008 Ozone standard to July 20, 2016. In December 2016 the EPA determined that the Houston-Galveston-Brazoria area had failed to attain the 2008 ozone standard by the 2016 attainment date. This finding reclassifies the HGB area from marginal to “moderate.”
In October 2015 the EPA issued a final rule lowering the primary and secondary NAAQS for ozone to a level of 70 parts per billion. States will have approximately one yearwere required to assess their attainment status and recommend designations to the EPA.EPA by October 2016. The following counties and parishes in Entergy’s service territory were recommended for non-attainment: in Louisiana, Ascension Parish, East Baton Rouge Parish, West Baton Rouge Parish, Iberville Parish, and Livingston Parish; in Texas, Montgomery County. The EPA will then have approximately ahas one year to review thosethese recommendations and make final designations. States are expected to file compliance plans by the end of 2018. The assessments likely will be based on data from 2014-2016. Entergy will continue to work with state environmental agencies on appropriate methods for assessing attainment and non-attainment with the new standard and, where necessary, in planning for compliance. Following designation approval by the EPA, states will be required to develop plans intended to return non-attainment areas to a condition of attainment. The timing for that action depends largely on the severity of non-attainment in a given area.
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 initially indicated that it would delay designations except for those areas with existing monitoring data from 2009 to 2011 indicating violations of the new standard. In August 2013 the EPA issued final designations for these areas. In Entergy’s utility service territory, only St. Bernard Parish in Louisiana is designated as non-attainment for the SO2 1-hour national ambient air quality standard of 75 parts per billion. Entergy does not have a generation asset in that parish. Pursuant to a court order issued in a proceeding in the U.S. District Court for the Northern District of California,In July 2016 the EPA will finalizefinalized another round of designations by July 2, 2016, for areas with newly monitored violations of the
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2010 standard and those with stationary sources that emit over a threshold amount of SO2. Counties and parishes in which Entergy owns and operates fossil generating facilities that are expected to be assessedwere included in this round of designations include Independence County and Jefferson County, Arkansas and Calcasieu Parish, Louisiana. In other areas, analysis is required once the EPA issues additional final regulationsIndependence County and guidance. In September 2015 the State of Arkansas recommended designations of “Unclassifiable/Attainment” for IndependenceCalcasieu Parish were designated “unclassifiable,” and Jefferson Counties. In September 2015 the State of Louisiana recommended a designation of “Attainment” for Calcasieu Parish.County was designated “unclassifiable/attainment.” In August 2015 the EPA issued a final data requirement rule for the SO2 1-hour standard. This rule will guide the process to be followed by the states and the EPA to determine the appropriate designation for the remaining unclassified
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areas in the country. Additional capital projects or operational changes may be required to continue operating Entergy facilities in areas eventually designated as in non-attainment of the standard or designated as contributing to non-attainment areas.
Hazardous Air Pollutants
The EPA released the final Mercury and Air Toxics Standard (MATS) rule in December 2011, which hashad a compliance date, with a widely granted one-year extension, of April 2016. In June 2015 the U.S. Supreme Court reversed a U.S. Court of Appeals for the D.C. Circuit decision and remanded to the D.C. Circuit the EPA’s finding that it was appropriate and necessary to regulate power plants under Clean Air Act section 112, ruling that the EPA must consider costs. This EPA finding underpins the MATS rule. In November 2015 the EPA released a Proposed Supplemental Finding that consideration of costs does not alter its previous conclusion that it is appropriate and necessary to regulate hazardous air pollutants from power plants. In December 2015 the D.C. Circuit issued a ruling to leave the rule in effect while EPA finalizes the appropriate and necessary finding to consider costs. Compliance with MATS was required by the Clean Air Act within three years, or by 2015, although certain extensions of this deadline were available from state permit authorities and the EPA. Entergy applied for and received a one-year extension for its affected facilities in Arkansas and Louisiana. The required controls have been installed and are being tested prior to full scale operation and to confirm regulatory compliance. Additional expenditures or operational modifications could be required for compliance depending on the final outcome of testing.at all affected Entergy units.
Cross-State Air Pollution
In March 2005 the EPA finalized the Clean Air Interstate Rule (CAIR), which was intended to reduce SO2 and NOx emissions from electric generation plants in order to improve air quality in twenty-nine eastern states. The rule required a combination of capital investment to install pollution control equipment and increased operating costs through the purchase of emission allowances. 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, CAIR was vacated and remanded toits subsequent versions, now known as the EPA by the D.C. Circuit in 2008. The court allowed CAIR to become effective in January 2009, while the EPA revised the rule. In July 2011 the EPA released its final Cross-StateCross State Air Pollution Rule (CSAPR, which previously was referred(CSAPR), have been remanded to as the Transport Rule). The rule was directed at limiting the interstate transport of emissions of NOxand 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 and others challenged these allocations. Litigation concerning several issues not determinedmodified by the Supreme Court continued inEPA on multiple occasions. In July 2015 the D.C. Circuit until July 2015, when that court invalidated the allowance budgets created by the EPA for several states, including Texas, and remanded that portion of the rule to the EPA for further action. The court did not stay or vacate the rule in the interim. CSAPR remains in effect.
The CSAPR Phase 1 implementation became effective January 1, 2015. Entergy has developed a compliance plan that could, over time, include both installation of controls at certain facilities and an emission allowance procurement strategy.
In November 2015September 2016 the EPA released a proposedfinalized the CSAPR update ruleUpdate Rule to address interstate transport for the 2008 ozone NAAQS. Starting in 2017 this proposal would reduce summertimethe final rule will require reductions in summer nitrogen oxides (NOXx) emissions from power plants in 23emissions. Several states, with significant reductions in some states such asincluding Arkansas and Mississippi. Entergy will continueTexas, filed a challenge to interact with state and federal agencies as the final rule is developed.Update Rule, which remains pending.
Regional Haze
In June 2005 the EPA issued its final Clean Air Visibility Rule (CAVR) regulations that potentially could result in a requirement to install SO2 and NOx pollution control technology as Best Available Retrofit Control Technology (BART) to continue operating certain of Entergy’s fossil generation units. The rule leaves certain CAVR determinations
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to the states. The
In Arkansas, the Arkansas Department of Environmental Quality (ADEQ) prepared a State Implementation Plan (SIP) for Arkansas facilities to implement its obligations under the CAVR. In April 2012 the EPA finalized a decision addressing the Arkansas Regional Haze SIP, in which it disapproved a large portion of the Arkansas Regional Haze SIP, including the emission limits for NOx and SO2 at White Bluff. This triggered a two-year timeframe for EPA to either approve a revised SIP issued by Arkansas or issue a Federal Implementation Plan (FIP). This two-year time frame expired in April 2014. By Court order, the EPA ishad to issue a final FIPfederal implementation plan (FIP) for Arkansas Regional Haze by no later than August 31, 2016. In April 2015 the EPA published a proposed FIP for Arkansas, taking comment on requiring installation of scrubbers and low NOx burners to continue operating both units at the White Bluff plant and both units at the Independence plant and NOx controls to
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continue operating the Lake Catherine plant. Entergy filed commentcomments by the deadline in August 2015. Among other comments, including opposition to the EPA’s proposed controls on the Independence units, Entergy proposed to meet more stringent SO2and NOxlimits at both White Bluff and Independence within three years of the effective date of the final FIP and to cease the use of coal at the White Bluff units in 2027 and 2028.
In September 2016 the EPA published the final Arkansas Regional Haze FIP. In most respects, the EPA finalized its original proposal but shortened the time for compliance for installation of the NOx controls. The FIP requires an emission limitation consistent with SO2 scrubbers at both White Bluff and Independence by October 2021 and NOx controls by April 2018. The EPA declined to adopt Entergy’s proposals related to ceasing coal use as an alternative to SO2 scrubbers for White Bluff SO2 BART. For some or all of the FIP, Entergy anticipates that Arkansas will submit a state plan (SIP) to replace the FIP. In November 2016, Entergy and other interested parties such as the State of Arkansas filed petitions for administrative reconsideration and stay at EPA as well as petitions for judicial review to the U.S. Court of Appeals for the Eighth Circuit. In February 2016, Entergy, the State of Arkansas, and other parties requested the Court to judicially stay the FIP. A decision is expected in 2017.
In Louisiana, Entergy is working with the LDEQ and the EPA to revise the Louisiana SIP for regional haze, which was disapproved in part in 2012. In September 2015 the Sierra Club filed suit against the EPAA proposed federal implementation plan is likely to be issued in the U.S. District CourtMarch 2017 with finalization in Washington, D.C. for failure either to approve a revised SIP issued by Louisiana or issue a FIP within two years of the partial Louisiana SIP disapproval. The suit requests that the U.S. District Court order the EPA Administrator to issue a regional haze and interstate transport FIP for Louisiana by a certain date. This would set the timing for a final approval of a revised SIP issued by Louisiana or a FIP issued by the EPA.December 2017. At this time, it is premature to predict what controls, if any, might be required for compliance. Entergy continues to monitor the submission and to file comments in the process as appropriate.
Fine Particle (PM2.5) National Ambient Air Quality Standard
In December 2012 the EPA released regulations that lowered the NAAQS for fine particle pollution or PM2.5. In January 2015 the EPA finalized area designations for this standard. All areas in Entergy’s service territory were designated as “Unclassifiable/Attainment” for this standard. Entergy will continue to monitor and engage, as necessary, in the state’s implementation process in Entergy states.
NNew and Existing Source Performance Standards for Greenhouse Gas Emissions
As a part of a climate plan announced in June 2013, President Obama directed the EPA was directed to (i) reissue proposed carbon pollution standards for new power plants by September 20, 2013, with finalization of the rules to occur in a timely manner; (ii) issue proposed carbon pollution standards, regulations, or guidelines, as appropriate, for modified, reconstructed, and existing power plants no later than June 1, 2014; (iii) finalize those rules by no later than June 1, 2015; and (iv) include in the guidelines addressing existing power plants a requirement that states submit to the EPA the implementation plans required under Section 111(d) of the Clean Air Act and its implementing regulations by no later than June 30, 2016. In January 2014 the EPA issued the proposed New Source Performance Standards rule for new sources. In June 2014 the EPA issued proposed standards for existing power plants. Entergy has been actively engaged in the rulemaking process, having submitted comments to the EPA in December 2014. The EPA issued the final rule for both new and existing sources in August 2015, and it was published in the Federal Register in October 2015. The rule, also called the Clean Power Plan, requires states to develop compliance plans with the EPA’s emission standards. In February 2016 the U.S. Supreme Court issued a stay halting the effectiveness of the rule until the rule is reviewed by the D.C. Circuit and the U.S. Supreme Court. Entergy continuesIt is also expected that the current administration will make modifications to reviewthis program. The cost and schedule for implementation of the 111(d) implementation rule and work with various stakeholders during the planning process; litigation has commenced regarding the rule and is expected to continue. Costs of implementation cannot be determined at this time and will depend largely on court decisions, administration modifications to the program, and any forthcoming state section 111(d)111 (d) implementation plans.
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Potential Legislative, Regulatory, and Judicial Developments
In addition to the specific instances described above, there are a number of legislative and regulatory initiatives concerning air emissions, as well as other media, that are under consideration at the federal, state, and local level. Because of the nature of Entergy’s business, the imposition of any of these initiatives could affect Entergy’s
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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;
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| • | introduction of bills in Congress and development of regulations by the EPA proposing further limits on NOx, SO2, mercury, and carbon dioxide and other air 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; |
efforts in Congress or at the EPA to establish a mandatory federal carbon dioxide emission control structure or unit performance standards;
revisions to the estimates of the Social Cost of Carbon used for regulatory impact analysis of Federal laws and regulations;
implementation of the Regional Greenhouse Gas Initiative by several states in the northeastern United States and similar actions in other regions of the 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 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 carbon dioxide emissions and risk. risk; and
the listing of additional species as threatened or endangered and the protection of critical habitat for these species.
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 anticipation of the imposition of carbon dioxide emission limits on the electric industry in the future, Entergy initiated actions designed to reduce its exposure to potential new governmental requirements related to carbon dioxide emissions. These voluntary actions included establishment of a formal program to stabilize power plant carbon dioxide emissions at 2000 levels through 2005, and Entergy succeeded in reducing emissions below 2000 levels. Total carbon dioxide emissions representing Entergy’s ownership share of power plants in the United States were approximately 53.2 million tons in 2000 and 35.6 million tons in 2005. In 2006, Entergy changed its method of calculating emissions to include emissions from controllable power purchases as well as its ownership share of generation. 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. In 2011, Entergy extended this commitment through 2020. Total carbon dioxide emissions representing Entergy’s ownership share of power plants and controllable power purchases in the United States were approximately 46.1 million tons in 2011, approximately 45.5 million tons in 2012, approximately 46.2 million tons in 2013, approximately 42.4 million tons in 2014, and approximately 39.5 million tons in 2015.2015, and 42.5 million tons in 2016. The decrease in this number sincefrom 2014 to 2015 is largely attributable to the impact on the calculation methodology of the Utility operating companies’ transition into the MISO system. Participation in this system resulted in fewer power purchases being classified as “controllable” and thus included in the calculation of the emissions total.
Entergy has prepared responses forparticipates in the Carbon Disclosure Project’s (CDP)M.J. Bradley & Associates’ Annual Benchmarking Air Emissions Report, an annual questionnaire foranalysis of the past several years and has given permission for those responses to be posted100 largest U.S. electric power producers. The report is available on the CDP’sM.J. Bradley website. This information, basedEntergy’s CO2 emissions are also third-party verified, and that certification is available on the American Carbon Registry website. Entergy participates annually in the Dow Jones Sustainability Index and in 2016 was listed on the North American Index.
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in part on an annual third-party greenhouse gas emissions inventory verification, commissioned by Entergy, provides information on a broader scope of emissions from overall operations.
Nelson Unit 6 (Entergy Louisiana)
Entergy 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 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. Settlement negotiations continueEntergy Louisiana has settled this matter with the LDEQ.
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. 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.
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 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. Entergy Wholesale Commodities’ Indian Point nuclear facility in New York is seeking a new Section 401 certification prior to license renewal under full reservation of rights.
Indian Point
For thirteen years, Entergy is involvedparticipated in an administrative permitting process with the New York State Department of Environmental Conservation (NYSDEC) for renewal of the Indian Point 2 and Indian Point 3 discharge permit. In November 2003That proceeding recently was settled along with other ongoing proceedings. For a discussion of the NYSDEC issued a draft permit indicating that closed cycle cooling would be considered the “best technology available” for minimizing alleged adverse environmental effects attributable to the intake of cooling water atrecent Indian Point subject to a feasibility determination and alternatives analysis for that technology, if Entergy applied for and received NRC license renewal for 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. Entergy 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.
An August 2008 ruling by the NYSDEC’s Assistant Commissioner restructured the permitting and administrative process, including the application of a new economic test designed to implement the U.S. Second 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 directed Entergy to develop detailed feasibility information regarding the construction and operation of cooling towers, and alternatives to closed cycle
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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 in June 2009, a plume and emissions report filed in September 2009, a technical feasibility report 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 requested that the NYSDEC Assistant Commissioner reconsider the New York standard in light of the U.S. Supreme Court decision reversing the Second Circuit’s alternative economic test adopted in the August 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 wholly 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 retrofitting with cooling towers are estimated to be at least $1.19 billion, in 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 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 construction of Entergy’s alternative technology proposal, wedgewire screens, is also subject to uncertainty. Hearings on certain issues began in 2011 in consolidation with certain issues in the water quality certification matter.
Additional hearings were held in July 2013 before the NYSDEC ALJs on environmental issues related to Indian Point’s wedgewire screen proposal as “best technology available.” In 2014, hearings were held on NYSDEC’s proposed best technology available, closed cycle cooling. NYSDEC also has proposed annual fish protection outages of 42, 62, or 92 days at both units or at one unit with closed cycle cooling at the other. The ALJs held a further legislative hearing and issues conference on this NYSDEC staff proposal in July 2014. NYSDEC staff subsequently withdrew the 92-day option. Hearings on the remaining outage proposals, including a 118-day option proposed by Riverkeeper, were held in September 2015, and post-hearing briefing on both the closed cycle cooling proposal and the outages proposal has been scheduled for May and July 2016. The estimated costs for the outage proposals range from $1.8 billion to $2.4 billion, and include direct costs, lost revenues, and operation and maintenance expenses. For additional discussion of this and other proceedings related to Indian Point,settlement, see “Entergy Wholesale Commodities AuthorizationsAuthorization to Operate Its Nuclear Power Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
316(b) Cooling Water Intake Structures
The EPA finalized 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. After litigation, in May 2014, the EPA issued a new final 316(b) rule, followed by publication in the Federal Register in August 2014, with the final rule effective in October 2014. Entergy is developing a compliance plan for each affected facility in accordance with the requirements of the final rule.
Entergy filed as a co-petitioner with the Utility Water Act Group a petition for review of the final rule. The case will be heard in the U.S. Second Circuit Court of Appeals. Entergy expects briefing on the case to occurbe finalized in 2016.early 2017.
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Coastal Zone Management Act
Before a federal licensing agency (such as the NRC) may issue a major license or permit for an activity within the federally designated coastal zone, the agency must be satisfied that the requirements of the Coastal Zone Management Act (CZMA), as applicable, have been met. In many cases, CZMA requirements are satisfied by the state’s written concurrence with a “consistency determination” filed by the federal license applicant explaining why the activity proposed to be federally licensed is consistent with the state’s coastal management program. The CZMA givesFor a discussion of the state six months to act once the consistency determination is deemed complete; failure to act is treated as a deemed concurrence. Entergy is pursuing three independent paths to ensure that CZMA requirements forrecent Indian Point license renewal are met. For additional discussion ofsettlement, including the CZMA proceedings related to Indian Point license renewal, see “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
Effluent Limitation Guidelines
In September 2015 the EPA issued the final rule updating the effluent limitation guidelines (ELG) for steam electric power plants. The final rule establishes Best Available Technology Economically Achievable, New Source Performance Standards, Pretreatment Standards for Existing Sources, and Pretreatment Standards for New Sources that may apply to discharges of six waste streams; flue gas desulfurization (FGD) wastewater, fly ash transport water, bottom ash transport water, flue gas mercury control wastewater, gasification wastewater, and combustion residual leachate. Entergy is currently assessing the impact of the final rule. While the rule overall is quite stringent, initial assessments indicate its impact to Entergy’s facilities will not be material; however it is expected to impact the design and operation of any newly constructed facilities.
Federal Jurisdiction of Waters of the United States
In September 2013 the EPA and the U.S. Army Corps of Engineers announced the intention to propose a rule to clarify federal Clean Water Act jurisdiction over waters of the United States. The announcement was made in conjunction with the EPA’s release of a draft scientific report on the “connectivity” of waters that the agency says will inform the rulemaking - this report was finalized in January 2015. The Final Rule was published in the Federal Register in June 2015. The rule could significantly increase the number and types of waters included in the EPA’s and the U.S. Army Corps of Engineers’ jurisdiction, which in turn could pose additional permitting and pollutant management burdens on Entergy’s operations. Entergy is actively engaged with the EPA and the U.S. Army Corps of Engineers to identify issues that require clarification in expected technical and policy guidance documents. The final rule has been challenged in federal court by several parties, including over twenty-fivethirty states. In August 2015 the District Court for North Dakota issued a preliminary injunction staying the new rule in 13 states. In October 2015 the U.S. Court of Appeals for the Sixth Circuit issued a nationwide stay of the rule. Entergy will continue to monitor this rulemaking and ensure compliance with existing permitting processes. In response to the stay, EPA and the U.S. Army Corps resumed nationwide use of the agencies’ regulations as they existed prior to August 27, 2015.
Groundwater at Certain Nuclear Sites
The NRC requires nuclear power plants to monitor and report regularly 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. 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 site groundwater at 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
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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 Arkansas Nuclear One, FitzPatrick, Indian Point, Palisades, Pilgrim, Grand Gulf, Vermont Yankee, and River Bend. Each of these sites has installed groundwater monitoring wells and implemented a program for testing groundwater at the sites for the presence of tritium and other radionuclides. Based on current information, the concentrations and locations of radionuclides detected at these plants pose no threat to public health or safety, but each site continues to evaluate the results from its groundwater monitoring program.
In early February 2016, Entergy disclosed that elevated tritium levels had been detected in samples from several monitoring wells that are part of Indian Point’s groundwater monitoring program. Investigation of the causesource of elevated tritium has determined that the source is under way,related to a temporary system to process water in preparation for the regularly scheduled refueling outage at Indian Point 2. The system was secured and groundwater monitoringis no longer in use and additional measures have been taken to prevent reoccurrence should the system be needed again. In June 2016, Indian Point detected trace
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amounts of cobalt 58 in a single well. This was associated with the draining and disassembly of a temporary heat exchanger operated in support of the Indian Point 2 outage. Oversight by NRC and other federal/state government bodies continues. The NRC has issued a Green Notice of Violation related to the adequacy of Entergy’s controls to prevent the introduction of radioactivity into the site groundwater.
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. Many states have adopted programs similar to CERCLA. Entergy subsidiaries in the Utility and Entergy 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’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 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 subsidiaries have established provisions for the liabilities for such environmental clean-up and restoration activities. Details of CERCLA and similar state program liabilities that are not de minimis are discussed in the “Other Environmental Matters” section below.
Coal Combustion Residuals
In June 2010 the EPA issued a proposed rule on coal combustion residuals (CCRs) that contained 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 reused in certain processes would remain excluded from hazardous waste regulation. In April 2015 the EPA published the final CCR rule with the material being regulated under the second scenario presented above - as non-hazardous wastes regulated under RCRA Subtitle D.
The final regulations create new compliance requirements including modified storage, new notification and reporting practices, product disposal considerations, and CCR unit closure criteria. Entergy believes that on-site disposal options will be available at its facilities, to the extent needed for CCR that cannot be transferred for beneficial reuse. As of December 31, 2015,2016, Entergy’s balance sheet includedhas recorded asset retirement obligations related to CCR management of $7.9$8.2 million, including $3.6$3.8 million at Entergy Arkansas, $1.7 million at Entergy Louisiana, $1.1 million at Entergy Mississippi, and $1.2$1.3 million at Entergy Texas.
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In December 2016 the Water Infrastructure Improvements for the Nation Act was signed into law, which authorizes states to regulate coal ash rather than leaving primary enforcement to citizen suit actions. States may submit to the EPA proposals for a permit programs. Entergy Corporation, Utility operating companies,is monitoring state agency actions and System Energywill participate in the regulatory development process.
Other Environmental Matters
Entergy Louisiana and Entergy Texas
Several class action and other suitslawsuits 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 premises (see “Litigation” below).
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Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, currently is 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, apparently was routed to a portion of the property for disposal. The same area also has been used as a landfill. In 1999, Entergy Gulf States, Inc. signed a second administrative consent order with the EPA to perform a 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. The EPA released the second Five Year Review in 2015. The EPA believes that the current remediation technique is insufficient, and Entergy will need to utilize other remediation technologies on the site. In July 2015, Entergy submitted a Focused Feasibility Study to the EPA outlining the potential remedies and the suggested installation of a waterloo barrier. The estimated cost for this remedy is approximately $2 million. Entergy expectsis awaiting comments and direction from the EPA on the Focused Feasibility Study and potential remedy selection in early 2016.selection. Entergy is continuing discussions with the EPA regarding the ongoing actions at the site.
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’s and Entergy New Orleans’s premises (see “Litigation” below).
Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The Texas Commission on Environmental Quality (TCEQ) notified Entergy Arkansas, Entergy Louisiana, Entergy New Orleans, and Entergy Texas that the TCEQ believes those entities are potentially responsible parties (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 subsidiaries sent transformers to this facility. Entergy Texas,Arkansas, Entergy Louisiana, and Entergy ArkansasTexas responded to an information request from the TCEQ and continue to cooperate in this investigation. Entergy TexasLouisiana and Entergy LouisianaTexas 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 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’ involvement at the site, while Entergy Arkansas likely will pay a de minimis amount. Current estimates, although variable depending on ultimate remediation design and performance, indicate that Entergy’s total share of remediation costs likely will be approximately $1.5 million to $2 million. Remediation activities continue at the site.
Entergy Mississippi, Entergy Louisiana, Entergy New Orleans, and Entergy Texas
The EPA notified Entergy Mississippi, Entergy Texas, and Entergy New Orleans that the EPA believes those entities are PRPs concerning contamination of an area known as “Devil’s Swamp Lake” near the Port of Baton Rouge,
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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.
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Entergy Arkansas
In April 2014 an EF4 tornado impacted two substation transformers in Entergy Arkansas’s Mayflower EHV substation. The tornado caused a release of approximately 25,000 gallons of non-PCB transformer oils, which subsequently flowed into a creek on Entergy Arkansas property. A report was made to the National Response Center, and several environmental agencies responded. Entergy initiated spill response activities within hours of the release with eventual oversight of the EPA and Arkansas Department of Environmental Quality (ADEQ) personnel. At the direction of the agencies, Entergy Arkansas has installed several temporary monitoring and recovery wells throughout the site and has regularly pumped and sampled the wells to determine the site meets regulatory screening limits. Acceptable screening limits have been achieved and Entergy Arkansas has received notification from the ADEQ that the site remediation is sufficient. Entergy Arkansas is awaiting a Nohas received confirmation from ADEQ of “No Further Action letter;Required.” There are no additional cleanup liability issues expected for the site; however, it is believed that the remaining liability at the site is minimal and should not exceed the existing provision of $.29 million. Remaining costs should be limited to administrative oversight charges from EPA and ADEQ.ADEQ may still be outstanding.
Entergy Texas
In December 2016 a transformer inside the Hartburg, Texas Substation had an internal fault resulting in a release of approximately 15,000 gallons of non-PCB mineral oil. Cleanup ensued immediately; however, rain caused much of the oil to spread across the substation yard and into a nearby wetland. The Texas Commission on Environmental Quality (TCEQ) and the National Response Center were immediately notified, and TCEQ responded to the site approximately two hours after the cleanup was initiated. The remediation liability is estimated at $1.4 million; however, this number could fluctuate depending on the remediation extent and wetland mitigation requirements.
Entergy
In May 2015 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. No injuries occurred due to the transformer failure or company response. An estimated 3,000 gallons of oil 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, and fire suppression. Once the fire was extinguished, Indian Point personnel and contractors began recovering free-product from the damaged transformer, the transformer containment moat, and the area surrounding the transformer. The United States Coast Guard designated Entergy as the responsible party under the Oil Pollution Act of 1990 and assessed a $1,000 civil penalty for the discharge of oil into navigable waters. As required, Entergy established a claims process including a voluntary hotline. Entergy received no reports to the voluntary hotline or claims under the established claims process. Additional on-site remedial work including subsurface investigation continues, and the State of New York and/or the EPA may assess a penalty due to the release of oil to waters of the state. Discussions withIn September 2016, Indian Point personnel identified an oil sheen in the state continue,discharge canal. Further investigation revealed that an estimated 600 gallons of lubricating oil had leaked from the Indian Point 3 turbine system. The leaking component has been taken out of service and Entergyno oil has recordedbeen discovered in the Hudson River. In October 2016 the New York Department of Environmental Conservation issued two notices of violation, one for each of these events, and a provisionproposed order on consent for the potential outcome2015 event. In January 2017, Entergy and the New York Department of Environmental Conservation resolved this matter.matter with an Order on Consent. The agreed Order requires Entergy to pay approximately $600 thousand in civil penalties, natural resource damages, and oversight costs. Additionally, Entergy will repair a 70-foot section of the discharge canal wall and will conduct daily visual inspections of the discharge canal wall to help identify additional material erosion or material structural deficiencies.
Litigation
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
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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)
Texas Power Price Lawsuit
See Note 2 to the financial statements for a discussion of this proceeding.
Mississippi Attorney General Complaint
See Note 2 to the financial statements for a discussion of this proceeding.
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Asbestos Litigation (Entergy Louisiana Entergy New Orleans, and Entergy Texas)
See Note 8 to the financial statements for a discussion of this litigation.
Employment and Labor-related Proceedings (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
See Note 8 to the financial statements for a discussion of these proceedings.
Employees
Employees are an integral part of Entergy’s commitment to serving customers. As of December 31, 2015,2016, Entergy subsidiaries employed 13,57913,513 people.
|
| | |
| Utility: | |
|
| Entergy Arkansas | 1,2171,242 |
|
| Entergy Louisiana | 1,6811,696 |
|
| Entergy Mississippi | 682709 |
|
| Entergy New Orleans | 292269 |
|
| Entergy Texas | 608619 |
|
| System Energy | — |
|
| Entergy Operations | 2,8802,948 |
|
| Entergy Services | 3,0433,126 |
|
| Entergy Nuclear Operations | 3,1212,850 |
|
| Other subsidiaries | 5554 |
|
| Total Entergy | 13,57913,513 |
|
Approximately 5,1004,900 employees are represented by the International Brotherhood of Electrical Workers, the Utility Workers Union of America, the International Brotherhood of Teamsters, the United Government Security Officers of America, and the International Union, Security, Police, Fire Professionals of America.
Availability of SEC filings and other information on Entergy’s website
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,
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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’s financial condition, results of operations, and liquidity. See “FORWARD-LOOKING INFORMATION.”
Utility Regulatory Risks
(Entergy Corporation, Entergy Arkansas, 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 arecan be 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 costs, 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.adjustment upon the initiative of a regulator or affected stakeholders.
In addition, regulators can initiate proceedings to investigate the prudence of costs in the Utility operating companies’ base rates and examine, among other things, the reasonableness or prudence of the companies’ operation and maintenance practices, level of expenditures (including storm costs and costs associated with capital projects), allowed rates of return and rate base, proposed resource acquisitions, and previously incurred capital expenditures that the operating companies seek to place in rates. The regulators can disallow costs subject to their jurisdiction 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. Traditional base rate proceedings, as opposed to formula rate plans, generally have long timelines, are primarily based on historical costs, and may or may not be limited in scope or duration by statute. The length of these base rate proceedings can cause the Utility operating companies and System Energy to experience regulatory lag in recovering costs through rates. Decisions are typically subject to appeal, potentially leading to additional uncertainty associated with rate case proceedings.
The base rates of Entergy Texas are established in traditional base rate case proceedings. Apart from base rate proceedings, Entergy Texas has also has filed to use rate riders to recover the revenue requirements associated with certain authorized historical costs. Specifically, Entergy Texas has recovered distribution-related capital investments andthrough the distribution cost recovery factor rider mechanism, transmission-related capital investments and certain non-fuel MISO charges.charges through the transmission cost recovery factor rider mechanism, and MISO fuel and energy-related costs through the fixed fuel factor mechanism. Entergy Texas is also required to make a filing every three years, at a minimum, reconciling its fuel and purchased power costs and fuel factor revenues. In the course of this reconciliation, the PUCT determines whether eligible fuel and fuel-related expenses and revenues are necessary and reasonable, and makes a prudence finding for each of the fuel-related contracts for the reconciliation period.
Between base rate cases, Entergy Arkansas and Entergy Mississippi are able to adjust base rates annually through formula rate plans that utilize a forward test years.year (Entergy Arkansas) or forward-looking features (Entergy Mississippi). In its pendingresponse to Entergy Arkansas’s application for a general change in rates Entergy Arkansas notifiedin 2015, the APSC that it is electingapproved Entergy Arkansas’s proposed formula rate plan rider pursuant to its election to have its rates regulated under a formula rate review mechanism pursuant to legislation enacted by the Arkansas General Assembly in early 2015. Entergy Arkansas submitted aThe APSC approved the formula rate plan tariff withincluding its use of a projected year test period and an initial five-year term for approval by the APSC.term. The initial five-year term expires in 2021 unless Entergy Arkansas requests, and the APSC approves, the extension of the formula rate plan tariff for an additional five years through 2026. In the event that Entergy Arkansas’ formula rate
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plan is terminated or is not extended beyond the initial term, Entergy Arkansas could file an application for a general change in rates that may include a request for continued regulation under a formula rate review mechanism. If Entergy Mississippi’s formula rate plan is terminated, it would revert to the more traditional rate case environment or seek approval of a new formula rate plan. Entergy Arkansas and Entergy Mississippi recover fuel and purchased energy and certain non-fuel costs through other APSC-approved and MPSC-approved tariffs, respectively.
Entergy Louisiana sets electric base rates annually through a formula rate plan using an historic test year. The form of the formula rate plan, on a combined basis, was approved in connection with the business combination of Entergy Louisiana and Entergy Gulf States Louisiana and largely followed the formula rate plans that were approved by the LPSC in connection with the full electric base rate cases filed by those companies in February 2013. The formula rate plan is approved for continued use through the test year 2016 filing. Entergy Louisiana’s electric formula rate plan increases are capped at a cumulative total of $30 million through the formula rate plan cycle. The LPSC also approved in the business combination Entergy Louisiana’s continuation of a mechanism to recover non-fuel MISO-related costs, which are calculated separately from the formula rate plan requirements, but embedded in the formula rate plan factor applied on customer bills. This recovery mechanism expires following the 2015 test year, and Entergy Louisiana has filed an application seeking to extend that mechanism, which is subject to review for renewaland approval by the LPSC. MISO fuel and energy-related costs are recoverable in Entergy Louisiana’s fuel adjustment clause. The formula rate plan retains exceptions from the rate cap/restrictions and sharing requirements for certain large capital investment projects, including acquisition or construction of generating facilities, as well as purchase power agreements approved by the Ninemile 6 generating facility.LPSC. In the event that the electric formula rate plans were terminated, or expired without renewal or extension, Entergy Louisiana would at that time revert to the more traditional rate case environment.
Entergy New Orleans previously operated under a formula rate plan that ended with the 2011 test year. Currently, based on a settlement agreement approved by the City Council, with limited exceptions, no action may be taken with respect to Entergy New Orleans’ base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. The limited exceptions include continued implementation of the remaining two yearsfinal year of a four-year phased-in rate increase for its recently acquired Algiers operations in the Fifteenth Ward of the City of New Orleans and certain exceptional cost increases or decreases in its base revenue requirement.
The Utility operating companies and System Energy, and the energy industry as a whole, have experienced a period of rising costs and investments, and an upward trend in spending, especially with respect to infrastructure investments, which is likely to continue in the foreseeable future and 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 the Utility operating companies, see Note 2 to the financial statements.
The Utility operating companies recover fuel, purchased power, and associated costs through rate mechanisms that are subject to risks of delay or disallowance in regulatory proceedings.
The Utility operating companies recover their fuel, purchased power, and associated 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, including the cost of replacement power purchased when generators experience outages, with the possibility of refunds to ratepayers, there exists some risk to the ultimate recovery of those costs. Regulators can also 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 and, therefore, there can be no assurance that existing recovery mechanisms will remain unchanged or in effect at all.
The Utility operating 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’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
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a description of fuel and purchased power recovery mechanisms and information regarding the regulatory proceedings for fuel and purchased power costs recovery, see Note 2 to the financial statements.
There is uncertainty regarding the effect of the termination of the System Agreement on the Utility operating companies.
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 hashad been approved by the FERC.
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Entergy Arkansas’s participation in the System Agreement terminated in December 2013, and Entergy Mississippi’s participation in the System Agreement terminated in November 2015. Pursuant to a settlement agreement approved by the FERC in December 2015, the System Agreement will terminateterminated in its entirety with respect to the remaining Utility operating companies on August 31, 2016.
There is uncertainty regarding the long-term effect of the termination of the System Agreement on the Utility operating companies because of the significant effect of the agreement on the generation and transmission functions of the Utility operating companies and the significant period of time (over 30 years) that it has been in existence. In the absence of the System Agreement, there is uncertainty around the effectiveness of governance processes and the potential absence of federal authority to resolve certain issues among the Utility operating companies and their retail regulators.
In addition, although the System Agreement will terminateterminated in its entirety in August 2016, there are a number of outstanding System Agreement proceedings at the FERC that may require future adjustments, including challenges to the level and timing of payments made by Entergy Arkansas under the System Agreement. The outcome and timing of these FERC proceedings and resulting recovery and impact on rates cannot be predicted at this time.
For further information regarding the regulatory proceedings relating to the System Agreement, see the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - System Agreement” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and Note 2 to the financial statements, System Agreement Cost Equalization Proceedings.statements.
The Utility operating companies are subject to economic risks associated with participation in the MISO markets and the allocation of transmission upgrade costs. The operation of the Utility operating companies’ transmission system pursuant to the MISO RTO tariff and their participation in the MISO RTO’s wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.
On December 19, 2013, the Utility operating companies integrated into the MISO RTO. For further information regarding the FERC and proceedings related to the MISO RTO, see the “Rate, Cost-recovery, and Other Regulation - Federal Regulation - Entergy’s Integration Into the MISO Regional Transmission Organization” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. MISO maintains functional control over the combined transmission systems of its members and administers wholesale energy and ancillary services markets for market participants in the MISO region, including the Utility operating companies. The Utility operating companies sell capacity, energy, and ancillary services on a bilateral basis to certain wholesale customers and offer available electricity production of their generating facilities into the MISO day-ahead and real-time energy markets pursuant to the MISO tariff and market rules. The Utility operating companies are subject to economic risks associated with participation in the MISO markets. MISO tariff rules and system conditions, including transmission congestion, could affect the Utility operating companies’ ability to sell power in certain regions and/or the economic value of such sales, and MISO market rules may change in ways including the implementation of competition among transmission providers, that cause additional risk.
The Utility operating companies participate in the MISO regional transmission planning process and are subject to risks associated with planning decisions that MISO makes in the exercise of control over the planning of the Utility operating companies’ transmission assets that are under MISO’s functional control. The Utility operating companies pay transmission rates that reflect the cost of transmission projects that the Utility operating companies do not own, which could increase cash or financing needs. The terms and conditions of the MISO tariff, including provisions related to the design and implementation of wholesale markets and the allocation of transmission upgrade costs, are subject to regulation by FERC. The operation of the Utility operating companies’ transmission system pursuant to the
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MISO tariff and their participation in the MISO wholesale markets may be adversely affected by regulatory or market design changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. In addition, orders from each of the Utility operating companies’ respective retail regulators generally require that the Utility operating companies make filings, within a specified period of their integration into MISO,
setting forth the results of analysis of the costs and benefits of continued membership in MISO and/or requesting approval of their continued membership in MISO, and the outcome of such proceedings may affect the Utility operating companies’ continued membership in MISO.
(Entergy Corporation, Entergy Arkansas, 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 effects on Entergy and those Utility operating companies affected by severe weather.
Entergy’s and its Utility operating companies’ results of operations, liquidity, and financial condition can be materially 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 effect on Entergy and those Utility operating companies affected by severe weather.
Nuclear Operating, Shutdown and Regulatory Risks
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy)
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities must consistently operate their nuclear power plants at high capacity factors in order to be successful, and lower capacity factors could materially affect Entergy’s and their results of operations, financial condition, and liquidity.
Nuclear capacity factors significantly affect the results of operations of certain Utility operating companies, System Energy, and Entergy Wholesale Commodities. Nuclear plant operations involve substantial fixed operating costs. Consequently, to be successful, a plant owner must consistently operate its nuclear power plants at high capacity factors. For the Utility operating companies that own nuclear plants, lower capacity factors can increase production costs by requiring the affected companies to generate additional energy, sometimes at higher costs, from their fossil 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. Entergy Wholesale Commodities’ forward sales are comprised of various hedge products, many of which have some degree of operational-contingent price risk. Certain unit-contingent contracts guarantee specified minimum capacity factors. In the event plants with these contracts were operating below the guaranteed capacity factors, Entergy would be subject to price risk for the undelivered power. Further, Entergy Wholesale Commodities’ nuclear forward sales contracts can also be on a firm LD basis, which subjects Entergy to increasing price risk as capacity factors decrease. Many of these firm hedge products have damages risk, capped through the use of risk management products.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities nuclear plant owners periodically shut down their nuclear power plants to replenish fuel. Plant maintenance and upgrades are often scheduled during such refueling outages. If refueling outages last longer than anticipated or if unplanned outages arise, Entergy’s and their results of operations, financial condition, and liquidity could be materially affected.
Outages at nuclear power plants to replenish fuel require the plant to be “turned off.” Refueling outages generally are planned to occur once every 18 to 24 months and average 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
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increase. Lower than forecasted capacity factors may cause Entergy Wholesale Commodities to experience reduced revenues and may also create damages risk with certain hedge products as previously discussed.
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Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities face risks related to the purchase of uranium fuel (and its conversion, enrichment, and fabrication), and the 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 affect Entergy’s and their results of operations, financial condition, and liquidity.
Based upon currently planned fuel cycles, Entergy’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 20162017 and beyond. The nuclear fuel supply portfolio for the Entergy Wholesale Commodities segment is being adjusted to reflect reduced overall requirements related to the planned permanent shutdown of the FitzPatrickPalisades, Pilgrim, Indian Point 2 and PilgrimIndian Point 3 plants and the recent shutdownplanned sale of the Vermont YankeeFitzPatrick plant. Entergy’s ability to purchase nuclear fuel at reasonably predictable prices, however, depends upon the performance reliability of uranium miners and enrichers. While there are a number of possible alternate suppliers that may be accessed to mitigate any 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. Entergy also may draw upon its own inventory intended for later 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. Market prices for nuclear fuel have been extremely volatile from time to time in the past. Although Entergy’s nuclear fuel contract portfolio provides a degree of hedging against market risks for several years, costs for nuclear fuel in the future cannot be predicted with certainty due to normal inherent market uncertainties, and price increases could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.
Entergy’s ability to assure nuclear fuel supply also depends upon the performance and reliability of conversion, enrichment, and fabrication services providers. These service providers are fewer in number than uranium suppliers. For conversion and enrichment services, Entergy diversifies its supply by supplier and country and may take special measures to ensure a reliable supply of enriched uranium for fabrication into nuclear fuel. For fabrication services, each plant is dependent upon the performance of the fabricator of that plant’s nuclear fuel; therefore, Entergy relies upon additional monitoring, inspection, and oversight of the fabrication process to assure reliability and quality of its nuclear fuel. Certain of the suppliers and service providers are located in or dependent upon countries, such as Russia, in which deteriorating economic conditions or international sanctions could restrict the ability of such suppliers to continue to supply fuel or provide such services. The inability of such suppliers or service providers to perform such obligations could materially affect the liquidity, financial condition, and results of operations of certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities.
Entergy Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business face the risk that the NRC will change or modify its regulations, suspend, not renew, or revoke their licenses, or increase oversight of their nuclear plants, which could materially 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, not renew, 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, or the NRC’s interpretation thereof, may require a substantial increase in capital expenditures or may result in increased operating or decommissioning costs and could materially affect the results of operations, liquidity, or financial condition of Entergy (through Entergy Wholesale Commodities), its Utility operating companies, or System Energy. A change in the classification of a plant owned by one of these companies under the NRC’s Reactor Oversight Process, which is the NRC’s program to collect information about plant performance, assess the information for its safety significance,
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and provide for appropriate licensee and NRC response, also could cause the owner of the plant to incur material additional costs as a result of the increased oversight activity and potential response costs associated with the change in classification. For additional information concerning the current classification of the plants owned by Entergy
Arkansas, Entergy Louisiana, System Energy, and the Entergy Wholesale Commodities business, see ENTERGY’S BUSINESS - Regulation of Entergy’s Business - Regulation of the Nuclear Power Industry - NRC Reactor Oversight Process in Part I, Item 1 and Note 8 to the financial statements.
Events at nuclear plants owned by one of these companies, as well as those owned by others, may lead to a change in laws or regulations or the terms of the applicable licenses, or the NRC’s interpretation thereof, or may cause the NRC to increase oversight activity or initiate actions to modify, suspend, or revoke licenses, shut down a nuclear facility, or impose civil penalties. As a result, if an incident were to occur at any nuclear generating unit, whether an Entergy nuclear generating unit or not, it could materially 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 earthquake of March 11, 2011 that affected the Fukushima Daiichi nuclear plants in Japan resulted in the NRC issuing threevarious orders effective on March 12, 2012 requiring U.S. nuclear operators, including Entergy, to undertake plant modifications or perform additional analyses that, among other things, have resulted in increased capital and operating costs associated with operating Entergy’s nuclear plants, some of which have been and will be material.
Certain of the Utility operating companies, System Energy, and Entergy Wholesale Commodities are exposed to risks and costs related to operating and maintaining their nuclear power plants, and their failure to maintain operational efficiency at their nuclear power plants could materially affect Entergy’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 the Entergy Wholesale Commodities business began commercial operations in the 1970s-1980s. Older equipment may require more capital expenditures to keep each of these nuclear power plants operating safely and 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.increased costs, some of which costs may not be fully recoverable by the Utility operating companies and System Energy in regulatory proceedings. Operations at any of the nuclear generating units owned and operated by Entergy’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 Utility operating companies and System Energy, this could result in certain costs being stranded and potentially not fully recoverable in regulatory proceedings. For 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. In addition, the operation and maintenance of Entergy’s nuclear facilities require the commitment of substantial human resources that can result in increased costs.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.plant systems. The issue is applicable at all nuclear units to varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
Moreover, Entergy is becoming more dependent on fewer suppliers for key parts of Entergy’s nuclear power plants that may need to be replaced or refurbished. In addition, certain major parts have long lead-times to manufacture if an unplanned replacement is needed. This dependence on a reduced number of suppliers and long lead-times on certain major parts for unplanned replacements could result in delays in obtaining qualified replacement parts and, therefore, greater expense for Entergy.
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The costs associated with the storage of the spent nuclear fuel of certain of the Utility operating companies, System Energy, and the 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 disposal facility, as well as interim storage and transportation requirements.
Certain of the Utility operating companies, System Energy and the owners of the Entergy Wholesale Commodities nuclear plants incur costs on a periodic basis for the on-site storage of spent nuclear fuel. The approval of a license for a national repository for the disposal 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
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associated with on-site 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 expressed its intention and taken specific steps to discontinue the Yucca Mountain project and study a new spent fuel strategy. The NRC licensing of the Yucca Mountain repository is effectively at a standstill. These actions may 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, 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 the companies’ nuclear sites.sites and maintenance costs on existing storage facilities may increase. The costs of on-site storage are also affected by regulatory requirements for such 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 Louisiana, and System Energy.Energy and Note 8 to the financial statements.
Certain of the Utility operating companies, System Energy, and the 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 effect on Entergy’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 Price-Anderson Act limits each reactor owner’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 $127.318$127.3 million per reactor. With 103102 reactors currently participating, this translates to a total public liability cap of approximately $13.114$13 billion per incident. The limit is subject to 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 Entergy Wholesale Commodities carry the maximum available amount of primary nuclear off-site liability insurance with American Nuclear Insurers (currently $375(which is $450 million for each operating site)site as of January 1, 2017). 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’s Utility operating companies, System Energy, and the Entergy 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 insurance level, up to a maximum of $127.318approximately $127.3 million per reactor per incident (Entergy’s maximum total contingent obligation per incident is $1.4$1.273 billion). The retrospective premium payment is currently limited to $18.963approximately $19 million per year per incident per reactor until the aggregate public liability for each licensee is paid up to the $127.318$127.3 million cap.
NEIL is a utility industry mutual insurance company, owned by its members. All member plants could be subject to an annual assessment (retrospective premium of up to 10 times current annual premium for all policies) should the surplus (reserve) be significantly depleted due to insured losses. As of April 1, 2015,December 31, 2016, the maximum annual assessment amounts total $124$135.2 million for the Utility plants and $127.7$127.4 million for the Entergy Wholesale Commodities plants. Retrospective Premium Insurancepremium insurance available through NEIL’s reinsurance treaty can cover the
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potential assessments. Theassessments and the Entergy Wholesale Commodities plants currently maintain the Retrospective Premium Insuranceretrospective premium insurance to cover thisthose potential assessment.assessments.
As an owner of nuclear power plants, Entergy participates in 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 the 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 Entergy Wholesale Commodities subsidiaries.
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 Entergy 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, as adjusted from time to time by rate regulators, are generally based upon operating license lives and trust fund balances as well as estimated trust fund earnings and decommissioning costs. In connection with the acquisition of certain nuclear plants, the Entergy Wholesale 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 Indian Point 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 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 hashad the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assignsassigned the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner may contractcould have contracted with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount. A request was made to the NRC for permission to transfer the Indian Point 3 and FitzPatrick decommissioning trusts to Entergy Nuclear Operations, Inc., which was received in January 2017. The decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants were transferred to Entergy Nuclear Operations, Inc. by the former owner in January 2017. As part of the Indian Point 1 and Indian Point 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund. As part of the Palisades transaction, the 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, the Entergy Wholesale Commodities business will dismantle the spent fuel storage facility and complete site decommissioning. The 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.
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, which deficiencies have now been corrected. An early plant shutdown, poor investment results or higher than anticipated decommissioning costs could cause trust fund assets to be insufficient to meet the decommissioning obligations, with the result that the Entergy 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’s Financial Discussion and Analysis for Entergy, Entergy Arkansas, Entergy Louisiana, and System Energy and Note 9 to the financial statements.
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Changes in NRC regulations or other binding regulatory requirements may cause increased funding requirements for nuclear plant decommissioning trusts.
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’, 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
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Discussion and Analysis for Entergy, Entergy Arkansas, 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 and decommissioning 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 fivemost of the six units in the current fleet of Entergy Wholesale Commodities nuclear power plants areis 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’s subsidiaries own nuclear generating units for legislative and regulatory changes that could lead to the shutdown of nuclear units, denial of license renewal applications, restrictions on nuclear units as a result of unavailability of sites for spent nuclear fuel storage and disposal, or other adverse effects on owning, operating and operatingdecommissioning 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 effect on Entergy’s results of operations, financial condition, and liquidity.
(Entergy Corporation)
A failure to obtain renewed licenses or other approvals required for the continued operation of the Entergy Wholesale CommoditiesCommodities’ Indian Point 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 CommoditiesCommodities’ Indian Point 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 original expiration date of the operating license for Indian Point 2 was September 2013 and the original expiration date of the operating license for Indian Point 3 was December 2015. 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 and, with respect to issues resolved by the ASLB, before the NRC on appeal.
In relation to Indian Point 2 and Indian Point 3, theThe New York State Department of Environmental Conservation has taken the position that these plant ownersIndian Point 2 and Indian Point 3 must obtain a new state-issued Clean Water Act Section 401 water quality certification as part of the license renewal process. In addition, before the NRC may issue renewed operating licenses it must resolve its obligation to address the requirements of the Coastal Zone Management Act (CZMA). For further information regarding these environmental regulations see the “Regulation of Entergy’s Business - Environmental Regulation - Clean Water Act” section in Part I, Item 1. For additional discussion of the 401 and CZMA proceedings related to Indian Point license renewal, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis. In January 2017, Entergy
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announced that it plans to shut down Indian Point 2 in 2020 and Indian Point 3 in 2021. The early and orderly shutdown is part of a settlement under which New York State has agreed to drop legal challenges and support renewal of the operating licenses for Indian Point. For additional discussion of the settlement agreement with New York, see the “Entergy Wholesale Commodities Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
If the NRC finally denies the applications for the renewal of operating licenses for one or more of the Entergy Wholesale CommoditiesIndian Point nuclear power plants, or a state in which any such nuclear power plant is located is ableif Indian Point fails to prevent the continued operation of such plant,obtain other approvals, 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 until the proposed shutdown date, 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 CommoditiesIndian Point nuclear power plants, see the “Entergy Wholesale Commodities
Authorizations to Operate Its Nuclear Plants” in Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
The decommissioning trust fund assets for the nuclear power plants owned by Entergy 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, the plants cost more to decommission than estimated, or if current regulatory requirements change, which then could require additional funding.
Under NRC regulations, Entergy Wholesale Commodities’ nuclear subsidiaries are permitted to project the NRC-required decommissioning amount, based on an NRC formula or a site-specific estimate, and the amount in each of the Entergy Wholesale Commodities nuclear power plant’s decommissioning trusts combined with other decommissioning financial assurances in place. The projections are made based on the operating license expiration date and the mid-point of the subsequent decommissioning process, or the anticipated actual completion of decommissioning if a site-specific estimate is used, for each of these nuclear power plants. As a result, if the projected amount of individual plants’ decommissioning trusts exceeds the NRC-required decommissioning amount, then its decommissioning obligations are considered to be funded in accordance with NRC regulations. If the projected costs do not sufficiently reflect the actual costs the applicable Entergy subsidiaries would be required to incur to decommission these nuclear power plants, andor funding is otherwise inadequate, or if the formula, formula inputs, 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 NRC 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 NRC’s formula. The NRC may also require a plan for the provision of separate funding for spent fuel management costs. In addition to NRC requirements, there are other decommissioning-related obligations for certain of the Entergy Wholesale Commodities nuclear power plants, which management believes it will be able to satisfy.
If any Entergy Wholesale Commodities subsidiary decidessubsidiaries have announced plans to sell the FitzPatrick nuclear power plant and shut down one of itsthe Pilgrim, Palisades, Indian Point 2 and Indian Point 3 nuclear power plants earlier than the scheduled shutdownrespective license expiration date of the plants (or the license expiration date assuming 20 year renewed licenses for Indian Point 2 and conductIndian Point 3). As discussed previously, the former owner of Indian Point 3 and FitzPatrick retained the decommissioning trusts and related liability to decommission these plants, but had the right to require the respective Entergy Wholesale Commodities nuclear plant owners to assume the decommissioning liability provided that it assigned the funds in the corresponding decommissioning trust, up to a specified level, to such owners. Alternatively, the former owner could have contracted with Entergy Nuclear, Inc. for the decommissioning work at a price equal to the funds in the corresponding decommissioning trust up to a specified amount. A request was made to the NRC for permission to transfer the Indian Point 3 and FitzPatrick decommissioning trusts to Entergy Nuclear Operations, Inc., which was received in January 2017. The decommissioning trusts and decommissioning liabilities for the Indian Point 3 and FitzPatrick plants were transferred to Entergy Nuclear Operations, Inc. by the former owner in January 2017. As part of the Indian Point 1 and Indian Point 2 purchase, the Entergy Wholesale Commodities nuclear power plant owner also funded an additional $25 million to a supplemental decommissioning trust fund. If decommissioning of these
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plants were conducted without the full benefit of a safe storage period, or if funding is otherwise inadequate for an earlier decommissioning, the applicable Entergy subsidiary may be unable to rely upon only the decommissioning trust to fund the entire decommissioning obligations,obligation, which would require it to obtain funding from other sources.
Vermont Yankee submitted notification of permanent cessation of operations and permanent removal of fuel from the reactor in January 2015 after final shutdown in December 2014. The Post Shutdown Decommissioning Activities Report for Vermont Yankee, including a site specific cost estimate, was submitted to the NRC in December 2014. Vermont Yankee’s future certifications to satisfy the NRC’s financial assurance requirements will now be based on the site specific cost estimate, including the estimated cost of managing spent fuel, rather than the NRC minimum formula for estimating decommissioning costs. Entergy expects that amounts available in Vermont Yankee’s decommissioning trust fund, including expected earnings, together with the credit facilities entered into in January 2015 that are expected to be repaid with recoveries from DOE litigation related to spent fuel storage, will be sufficient to cover expected costs of decommissioning, spent fuel management costs, and site restoration. Future NRC filings will determine whether any other financial assurance may be required, including additional funding for spent fuel management, which will be required until the federal government takes possession of the fuel and removes it from the site, per its current obligation. In June 2015 the NRC granted an exemption allowing use of Vermont Yankee’s decommissioning trust funds for operational spent fuel management activities.activities at that site. In August 2015, Vermont and two Vermont utilities filed a petition in the U.S. Court of Appeals for the D.C. Circuit challenging the NRC’s issuance of that exemption. IfIn February 2016 the appeal werecourt dismissed the petition as premature because Vermont and the utilities had requested the NRC to resultreconsider a number of issues related to Vermont Yankee's use of the decommissioning trust fund including use to pay for spent fuel management expenses pursuant to the exemption granted in June 2015. In October 2016 the NRC denied Vermont's and the utilities' request for a final decision denyinghearing and other relief, including their challenge to the propriety of the exemption’s issuance, but directed the NRC staff to conduct an assessment of any environmental impacts associated with the exemption. In November 2016, Entergy announced that it has entered into a purchase and sale agreement with NorthStar Group Services, Inc. to sell to a NorthStar subsidiary 100% of the membership interests in Entergy Nuclear Vermont Yankee, the exemption,owner of the Vermont Yankee would haveplant. The sale of Entergy Nuclear Vermont Yankee to satisfyNorthStar will include the NRC that it had a plantransfer of Entergy Nuclear Vermont Yankee’s nuclear decommissioning trust and its obligations for spent fuel management and decommissioning and is subject to obtain additional funds to enable it to pay for these costs untilregulatory approvals and other closing conditions. See the federal government takes possession of the fuel and removes it“Entergy Wholesale Commodities Exit from the site.Merchant Power Business - Shutdown and Planned Sale of Vermont Yankee” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries and Note 14 to the financial statements for further information about the agreement to sell Entergy Nuclear Vermont Yankee to a subsidiary of NorthStar.
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 Entergy Wholesale Commodities nuclear power plants or may restrict the decommissioning-related costs that can be paid from the
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decommissioning trusts. As a result, under any of these circumstances, Entergy’s results of operations, liquidity, and financial condition could be materially affected.
Entergy Wholesale Commodities nuclear power plants are exposed to price risk.
Entergy and its subsidiaries do not have a regulator-authorized rate of return on their capital investments in non-utility businesses. In particular, the sale of capacity and energy from the Entergy Wholesale Commodities nuclear power plants, 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, 2015,2016, Entergy Wholesale Commodities’ nuclear power generation plants had sold forward 86%, 63%, 21%, 26%,87% in 2017, 56% in 2018, and 27%5% in 2019 of its generation portfolio’s planned energy output, for 2016, 2017, 2018, 2019reflecting the planned shutdown or sale of the Entergy Wholesale Commodities nuclear power plants by 2021.
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Market conditions such as product cost, market liquidity, and other portfolio considerations influence the product and contractual mix. The obligations under unit-contingent agreements depend 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. Firm 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 the plants do not run as expected and market prices exceed contract prices.
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 effects of sustained low natural gas prices and power market structure challenges have resulted in lower market prices for electricity in the power regions where the Entergy Wholesale Commodities nuclear power plants are located. The market price trend presents a challenging economic situation for the Entergy Wholesale Commodities plants. The severity of the challenge varies for each of the plants based on a variety of factors such as their market for both energy and capacity, their size, their contracted positions, and the amount of investment required to continue to operate and maintain the safety and integrity of the plants, including the estimated asset retirement costs. In addition, currently the market design under which the plants operate does not adequately compensate merchant nuclear plants for their environmental and fuel diversity benefits in the region. These conditions were primary factors leading to Entergy’s decision to shut down (or sell) Entergy Wholesale Commodities’ nuclear power plants before the end of their operating licenses (or requested operating licenses for Indian Point 2 and Indian Point 3).
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, Entergy Wholesale Commodities’ contract portfolio may have average contract prices above or below current market prices, including at the expiration of the contracts, which may significantly affect Entergy Wholesale Commodities’ results of operations, financial condition, or liquidity. New hedges are generally layered into on a rolling forward basis, which tends to drive hedge over-performance to market in a falling price environment, and hedge underperformance to market in a rising price environment; however, hedge timing, product choice, and hedging costs will also affect these results. See the “Results of Operations - Realized Revenue per MWh for Entergy Wholesale Commodities Nuclear PlantsMarket and Credit Risk Sensitive Instruments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries. Since Entergy Wholesale Commodities has announced the operating licenses for Indian Point 2 and Indian Point 3 expired in 2013 and 2015, respectively (see discussion above regarding the continued operationclosure (or sale) of Indian Point 2 and 3 past the license expiration dates), and as a consequence of any delays in obtaining extension of the operating licenses and any other approvals required for continued operation of theits nuclear plants, Entergy Wholesale Commodities may
enter into fewer unit-contingent forward sales contracts for output from such plants for periods beyond the license expiration.plants.
Among the factors that could affect market prices for electricity and fuel, all of which are beyond Entergy’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;
seasonality and realized weather deviations compared to normalized weather forecasts;
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;
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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 or distributed generation;
regulatory policies of state agencies that affect the willingness of Entergy 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 Wholesale 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 Wholesale Commodities’ nuclear markets;
union and labor relations;
changes in Federal and state energy and environmental laws and regulations and other initiatives, such as the Regional Greenhouse Gas Initiative, including but not limited to, the price impacts of proposed emission controls such as the Regional Greenhouse Gas Initiative (RGGI);controls;
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.
The 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.
The 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 Entergy 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 owners of the Entergy Wholesale Commodities nuclear power plants that generates electricity, as well as Entergy Nuclear Power Marketing, LLC, is a “public utility” under the Federal Power Act by virtue of making wholesale sales of electric energy and/or owning wholesale electric transmission facilities. The FERC has granted these generating and power marketing companies the authority to sell electricity at
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market-based rates. The FERC’s orders that grant the Entergy 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 Entergy Wholesale Commodities business can exercise market power in transmission or generation, create barriers to entry, or engage in abusive affiliate transactions. In addition, the Entergy 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 Entergy 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 Entergy Wholesale Commodities business charges for power from its facilities.
The Entergy 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 Entergy Wholesale
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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 substantialis subject to 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 Entergy Wholesale Commodities business. In addition, in some of these markets, interested parties have proposed 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. 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 Entergy Wholesale Commodities business’ results of operations, financial condition, and liquidity could be materially 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 the operations of such assets. Projected net cash flows depend on the expected operating life of the assets, 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 and capacity over the remaining life of the assets. In particular, the assets of the Entergy Wholesale Commodities business are subject to further impairment if adverse market conditions arise and continue (such as expected long-term declines in market prices for electricity), if adverse regulatory events occur (includingconnection with respectthe closure or sale of the plants discussed below. Moreover, prior to environmental regulation), if there is a reduction in the expected remaining useful lifeclosure or sale of a unit, if a unit ceases operation or if a unit’s operating license is not renewed. Moreover,these plants, 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, a reduction in the expected remaining useful life of a unit (including if the operating licenses for the Indian Point power plants are not renewed by the NRC), or a decline in observable industry market multiples could all result in potential additional impairment charges for the affected assets.
As discussed in the “Entergy Wholesale Commodities - Property”section in Part I, Item 1, the original expiration dates of the operating licenses for Indian Point 2 and Indian Point 3 were 2013 and 2015, respectively (see discussion above regarding the continued operation of Indian Point 2 and 3 past the license expiration dates),and are currently the subject of license renewal processes at the NRC and the state in which the plants operate. On August 27, 2013, Entergy announced its plan to close and decommission Vermont Yankee. Vermont Yankee ceased power production in the fourth quarter 2014 at the end of a fuel cycle. This decision was approved by the Board in August 2013, and resulted in the recognition of impairment charges in 2013 and 2014. In October 2015, Entergy determined that it will close the Pilgrim and FitzPatrick plants. The Pilgrim plant will cease operations no later than June 1, 2019. FitzPatrick iswas expected to shut down at the end of its current fuel cycle, planned for January 27, 2017.2017, but in August 2016, Entergy entered into an agreement to sell the FitzPatrick plant to Exelon Generation Company, LLC which will continue to operate the plant. During the third quarter 2015, Entergy recorded impairment and other related charges to write down the carrying values of the FitzPatrick and Pilgrim plants and related assets to their fair values. In addition, in the fourth quarter 2015, Entergy recorded impairment and other related charges to write down the carrying value of the Palisades plant and related assets to their fair value. In December 2016, Entergy reached an agreement with Consumers Energy to terminate the PPA for the Palisades plant in 2018. If the agreement receives regulatory approval, Palisades will shut down in 2018. In January 2017, Entergy announced that it reached a settlement with New York State and plans to close the Indian Point 2 plant in 2020 and the Indian Point 3 plant in 2021. As a result, in the fourth quarter of 2016, Entergy recorded impairment and other related charges to write down the carrying values of the Palisades and Indian Point 2 and Indian Point 3 plants and related assets to their fair value. In addition to the impairments and other related charges, Entergy has incurred severance and employee retention costs and expects to incur additional charges from 2016 into mid-2019through 2021 relating to the decisions to shut down Vermont Yankee, FitzPatrick,Palisades, Pilgrim, Indian Point 2 and Pilgrim. Indian Point 3, and the decision to sell FitzPatrick.
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If Entergy concludes that any of its nuclear power plants is unlikely to operate through its current useful life, which conclusion would be based on a variety of factors, such a conclusion could result in ana further 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. For further information regarding evaluating long-lived assets for impairment, see the “Critical Accounting Estimates - Nuclear Decommissioning CostsImpairment of Long-lived Assets and Trust Fund Investments” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries.Subsidiaries and for further discussion of the impairment charges, see Note 14 to the financial statements.
General Business
(Entergy Corporation, Entergy Arkansas, 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 Entergy’s and its subsidiaries’ ability to meet liquidity needs, access capital and operate and grow their businesses, and the cost of capital.
Entergy’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 and Entergy Wholesale Commodities. In addition, Entergy’s and the Utility operating 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’s service territory with Hurricane Katrina and Hurricane Rita in 2005, Hurricane Gustav and Hurricane Ike in 2008, and Hurricane Isaac in 2012. The occurrence of one or more contingencies, including a delay in regulatory recovery of fuel or 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 inability to raise capital on favorable terms, particularly during times of uncertainty in the capital markets, could negatively affect Entergy and its subsidiaries’ ability to maintain and to expand their businesses. Events beyond Entergy’s control, such as the volatility and disruption in global capital and credit markets in 2008 and 2009, may
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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 Corporation’s ability to sustain its current common stock dividend level.
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(Entergy Corporation, Entergy Arkansas, 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.
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 each Registrant’s regulatory framework, ability to recover costs and earn returns, diversification and financial strength and liquidity. If one or more rating agencies downgrade Entergy Corporation’s, any of the Utility operating companies’, or System Energy’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 collateral demands may be triggered by the terms of a number of commodity contracts, leases, and other agreements.
Most of Entergy Corporation’s and its subsidiaries’ large customers, suppliers, and counterparties require sufficient creditworthiness to enter into transactions. If Entergy Corporation’s or its 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, 2015,2016, based on power prices at that time, Entergy had liquidity exposure of $142$128 million under the guarantees in place supporting Entergy Wholesale Commodities transactions and $14$8 million of posted cash collateral. In the event of a decrease in Entergy Corporation’s credit rating to below investment grade, based on power prices as of December 31, 2015,2016, Entergy would have been required to provide approximately $52$57 million of additional cash or letters of credit under some of the agreements. In the event of a decrease in the credit ratings of Entergy’s Utility operating companies to below investment grade, those companies collectively could be required to provide up to $50 million of additional cash or letters of credit to MISO. As of December 31, 2015,2016, the liquidity exposure associated with Entergy Wholesale Commodities assurance requirements, including return of previously received collateral from counterparties, would increase by $98$238 million for a $1 per MMBtu increase in gas prices in both the short- and long-term markets.
Entergy and its subsidiaries’ ability to successfully complete strategic transactions, including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions, is subject to significant risks, including the risk that required regulatory or governmental approvals may not be obtained, risks relating to unknown or undisclosed problems or liabilities, and the risk that for these or other reasons, Entergy and its subsidiaries may be unable to achieve some or all of the benefits that they anticipate from such transactions.
From time to time, Entergy and its subsidiaries have pursued and may continue to pursue strategic transactions including merger, acquisition, divestiture, joint venture, restructuring or other strategic transactions. In particular, as discussed in the “Capital Expenditure Plans and Other Uses of Capital - Union“Entergy Wholesale Commodities Exit from the Merchant Power Station Purchase Agreement”Business” section of Management’s Financial Discussion and Analysis for Entergy Corporation and Subsidiaries, certain of Entergy’s subsidiaries havein August 2016, Entergy entered into an asset purchase agreement to acquiresell the Union Power Station, consisting
100% of four natural gas-fired, combined-cycle gas turbinethe membership interests in Entergy Nuclear Vermont Yankee, which owns the Vermont Yankee plant. In addition, as part of Entergy’s plan to exit the merchant power blocks, each rated at 495 MW (summer rating), from Union Power Partners, L.P. This transaction isbusiness, it plans to shut down its remaining merchant nuclear power plants by 2021. These transactions are subject to regulatory approval and other material conditions or contingencies. The failure to complete this transactionthese transactions or any future strategic transaction successfully or on a timely basis could have an adverse effect on Entergy’s financial condition, results of operations and the market’s perception of Entergy’s ability to execute its strategy. Further, this transaction,these transactions, and any completed or future strategic transactions, involve substantial risks, including the following:
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the disposition of a business or asset may involve continued financial involvement in the divested business, such as through continuing equity ownership, transition service agreements, guarantees, indemnities, or other current or contingent financial obligations;
Entergy may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner when it decides to sell an asset or a business, which could delay the accomplishment of its strategic objectives. Alternatively, Entergy may dispose of a business or asset at a price or on terms that are less than what it had anticipated, or with the exclusion of assets that must be divested or run off separately;
the disposition of a business could result in impairments and related write-offs of the carrying values of the relevant assets;
acquired businesses or assets may not produce revenues, earnings or cash flow at anticipated levels;
acquired businesses or assets could have environmental, permitting or other problems for which contractual protections prove inadequate;
Entergy and/or its subsidiaries may assume liabilities that were not disclosed to them, that exceed their estimates, or for which their rights to indemnification from the seller are limited;
the disposition of a business, including Entergy’s planned exit from the merchant power business, could divert management’s attention from other business concerns;
Entergy and/or its subsidiaries may be unable to obtain the necessary regulatory or governmental approvals to close a transaction, such approvals may be granted subject to terms that are unacceptable to them, or Entergy or its subsidiaries otherwise may be unable to achieve anticipated regulatory treatment of any such transaction or acquired business or assets; and
Entergy or its subsidiaries otherwise may be unable to achieve the full strategic and financial benefits that they anticipate from the transaction, or such benefits may be delayed or may not occur at all.
Entergy may not be successful in managing these or any other significant risks that it may encounter in acquiring or divesting a business, or engaging in other strategic transactions, which could have a material adverse effect on its business.
The construction of, and capital improvements to, power generation facilities involve substantial risks. Should construction or capital improvement efforts be unsuccessful, the financial condition, results of operations, or liquidity of Entergy and the Utility operating companies could be materially affected.
Entergy’s and the Utility operating 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. In addition, the Utility operating companies could be exposed to higher costs and market volatility, which could affect cash flow and cost recovery, should their respective regulators decline to approve the construction of new generation needed to meet the reliability needs of customers at the lowest reasonable cost. 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’ service territory, and as to the Entergy Wholesale Commodities business, see the “Capital Expenditure Plans and Other Uses of Capital” section of Management’s Financial Discussion and Analysis for Entergy and each of the Registrant Subsidiaries.
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The Utility operating companies, System Energy, and the Entergy Wholesale Commodities business may incur substantial costs to fulfill their obligations related to environmental and other matters.
The businesses in which the Utility operating companies, System Energy, and the Entergy 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 Entergy 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 Entergy Wholesale Commodities business manage air emissions, discharges to water, wetlands impacts, solid and hazardous waste storage and disposal, cooling
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and service water intake, the protection of threatened and endangered 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 Entergy 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’ 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 Entergy Wholesale Commodities business potentially 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 Entergy Wholesale Commodities 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 Entergy 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 emissions from 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 and the resulting need to shift course, both operationally and economically, depending on the nature of the changes. Risks relating to global climate change, initiatives to compel greenhouse gas emission reductions, and water availability issues are discussed below.
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
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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.
(Entergy Corporation, Entergy Arkansas, 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 affect the Utility operating companies’ results of operations.
Temperatures above normal levels in the summer tend to increase summerelectric cooling electricity demand and revenues, and temperatures below moderatenormal levels in the winter tend to increase winter heating electricityelectric and gas heating demand and revenues. As a corollary, moderate temperatures in either season 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’ 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 effect on the Utility operating companies’ financial condition, results of operations, and liquidity.
Entergy’s electricity sales volumes are affected by a number of factors, including the state of the national and regional economies,economic conditions, weather, customer bill sizes (large bills tend to induce conservation), trends in energy efficiency, new technologies and self generation alternatives, including the willingness and ability of large industrial customers to develop co-generation facilities that greatly reduce their demand from Entergy. Some of these factors are inherently cyclical or temporary in nature, such as the weather or economic conditions, and rarely have a long-lasting impacteffect on Entergy’s operating results. Others, such as the increasing adoption of energy efficient appliances, andnew building codes, and new technologies are having a more permanent impacteffect of reducing sales growth rates from historical norms. Newer technologies such as distributedDistributed generation havehas not yet had a substantive impact on Entergy’s electricity sales yet, but further advances have the potential to do so in the future. Entergy’sElectricity sales to industrial sales,customers, in particular, benefit from steady economic growth and favorable commodity prices and are also sensitive to changes in conditions in the markets in which its customers operate. Any negative change in any of these or other factors has the potential to result in slower sales growth or sales declines and increased bad debt expense, which could materially affect Entergy’s and the Utility operating companies’ results of operations, financial condition, and liquidity.
The effects of climate change and environmental and regulatory obligations intended to compel greenhouse gas emission reductions or to place a price on greenhouse gas emissions could materially affect the financial condition, results of operations, and liquidity of Entergy, the Utility operating companies, System Energy, and the Entergy Wholesale Commodities business.
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’s 2007 decision holding that the EPA has authority to regulate emissions of CO2 and other “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. During 2012 and 2014, EPA proposed CO2 emission standards for new and existing sources; EPA finalized these standards in 2015. 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. The impact that recent changes in the federal government will have on existing and pending environmental laws and regulations related to greenhouse gas emissions is currently unclear.
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Developing and implementing plans for compliance with greenhouse gas emissions reduction requirements can lead to additional capital, personnel, and operation and maintenance 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. These requirements could, in turn, lead to changes in the planning or operations of balancing authorities or organized markets in areas where the Utility operating companies, System Energy, or Entergy Wholesale Commodities do business. 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, civil penalties, and exposure to third 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
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resisted by Entergy’s regulators and, in extreme cases, Entergy’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 could make some of Entergy’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 affect the financial condition, results of operations and liquidity of Entergy and its subsidiaries. In addition, lawsuits have occurred 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 may seek injunctive relief, monetary compensation, and punitive damages.
In addition to the regulatory and financial risks associated with climate change discussed above, potential 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 increases in precipitation, drought, or changes in average temperatures), and potential increased impacts of extreme weather conditions or storms. Entergy subsidiaries own assets in, and 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’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 effect on Entergy’s, Entergy Wholesale Commodities’, System Energy’s, and the Utility operating companies’ financial condition, results of operations, and liquidity.
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 the Entergy Wholesale Commodities business.
Water is a vital natural resource that is also critical to the Utility operating companies’, System Energy’s, 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
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various provisions of the Clean Water Act and/or state water pollution control provisions. 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 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, fuel requirements, and inventories of natural gas, uranium and its conversion and enrichment, 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 affect Entergy’s and its 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’s or its subsidiaries’ credit quality or changes in the market prices of energy commodities could increase the cash or letter of credit collateral required to be posted in connection with hedging and risk management activities, which could materially affect Entergy’s or its subsidiaries’ liquidity and financial position.
The Utility operating companies and the Entergy Wholesale Commodities business are exposed to the risk that counterparties may not meet their obligations, which may materially affect the Utility operating companies and Entergy Wholesale Commodities.
The hedging and risk management practices 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 perform, Entergy or its subsidiaries may enforce and recover the proceeds from the credit support provided and acquire alternative hedging arrangements, 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’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 affect the adequacy of its liquidity sources.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Wall Street Transparency and Accountability Act of 2010 and rules and regulations promulgated under the act may adversely affect the ability of the Utility operating companies and the 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 (Act), and the rules and regulations promulgated under the act impose governmental regulation on the over-the-counter derivative market, including the commodity swaps used by the Utility operating companies and the Entergy Wholesale Commodities business to 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. Entergy is not a swap dealer or a major swap participant, and does not expect to qualify as either in the future. Non-swap dealers and non-major swap participants, such as Entergy, 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 limits may also apply to certain swaps activities. Position limit rules promulgated by the Commodity Futures Trading Commission were vacated by the US District Court for the District of Columbia. The
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
Commodity Futures Trading Commission has subsequently proposed new position limit rules. If the Commodity Futures Trading Commission’s issues final position limit rules, those rules 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 rulemaking has been largely completed. Both the Utility operating companies and the 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 post margin in connection with existing or future commodity swaps in addition to any margin currently posted by such entities, such entities may need to secure additional sources of capital to meet such liquidity needs or cease utilizing such commodity swaps.
Market performance and other changes may decrease the value of benefit plan assets, which then could require additional funding and result in increased benefit plan costs.
The performance of the capital markets affects the values of the assets held in trust under Entergy’s pension and postretirement benefit plans. A decline in the market value of the assets may increase the funding requirements relating to Entergy’s benefit plan liabilities and also result in higher benefit costs. As the value of the assets decreases, the “expected return on assets” component of benefit costs decreases, resulting in higher benefits costs. Additionally, asset losses are incorporated into benefit costs over time, thus increasing benefits costs. Volatility in the capital markets has affected the market value of these assets, which may affect Entergy’s planned levels of contributions in the future. Additionally, changes in interest rates affect the liabilities under Entergy’s pension and postretirement benefit plans; as interest rates decrease, the liabilities increase, potentially requiring additional funding and recognition of higher liability carrying costs. 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. For further information regarding Entergy’s pension and other postretirement benefit plans, refer to the “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” section of Management’s Financial Discussion and Analysis for Entergy and each of its Registrant Subsidiaries and Note 11 to the 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. The 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.
Domestic or international terrorist attacks, including cyber attacks, and failures or breaches of Entergy’s and its subsidiaries’ technology systems may adversely affect Entergy’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’s generation facilities, transmission operations centers, or distribution infrastructure used to manage and transport power to customers. An actual act could affect Entergy’s ability to operate, including its ability to operate the information technology systems and network infrastructure on which it relies to conduct its business. The Utility operating companies also face heightened risk of an act or threat by cyber criminals, intent on accessing personal information for the purpose of committing identity theft.
Entergy and its subsidiaries operate in a highly regulated industry that requires the continued operation of sophisticated information technology systems and network infrastructure in accordance with prescriptive standards. Despite the implementation of multiple layers of security by Entergy and its subsidiaries, technology systems remain vulnerable to potential threats that could lead to unauthorized access or loss of availability to critical systems essential to the reliable operation of Entergy’s electric system. If Entergy’s or its subsidiaries’ technology systems were compromised and unable to recover timely to a normal state of operations, Entergy or its subsidiaries may be unable to perform critical business functions that are essential to the company’s well-being and the health, safety, and security needs of its customers. In addition, an attack on its information technology infrastructure may result in a loss of its confidential, sensitive, and proprietary information, including personal information of its customers, employees, vendors, and others in Entergy’s care.
If any such attacks, failures or breaches were to occur, Entergy’s and the Utility operating companies’ business, financial condition, and results of operations could be materially and adversely affected. The risk of such attacks, failures, or breaches 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, and for systems to protect its information technology and network infrastructure systems. Such events may also expose Entergy to an increased risk of judgments and fines.
Changes in taxation as well as the inherent difficulty in quantifying potential tax effects of business decisions could negatively impact Entergy’s, the Utility operating companies’, and System Energy’s results of operations, financial condition and liquidity.
Entergy and its subsidiaries make judgments regarding the potential tax effects of various 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 provisions 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 benefits have already been reflected in the financial statements. Changes in 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, the Utility operating companies’, and System Energy’s results of operations, financial condition, and liquidity.
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
The Trump administration has included as part of its agenda a potential reform of U.S. tax laws, and House Republicans plan to advance their tax reform “blueprint.” Tax reform proposals call for, among other items, a reduction in the corporate federal income tax rate from the current 35% to as low as 15%, the immediate deduction of capital investment expenditures, and full or partial elimination of debt interest expense deductions. Further, for the Utility operating companies, regulators may impose rate reductions to provide the benefit of any income tax expense reductions to customers and refund “excess” deferred income taxes. For these reasons, Entergy, the Utility operating companies, and System Energy cannot predict the effect any potential changes may have on their future results of operations, cash flows, or financial position, and such changes could be significant.
For further information regarding Entergy’s income taxes, refer tosee Note 3 to the financial statements.
(Entergy New Orleans)
The effect of higher purchased gas cost charges to customers may adversely affect Entergy New 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 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’s bill and may be adjusted monthly, represent gas commodity costs that Entergy New Orleans recovers from its customers. Entergy New 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 New Orleans, customer
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
usage may decrease, especially in weaker economic times, resulting in lower distribution charges for Entergy New 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’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. 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 onexpires in November 1, 2024. System Energy filed in October 2011 an application with the NRC for an extension of Grand Gulf’s operating license to 2044. 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.
For information regarding the Unit Power Sales Agreement, the sale and leaseback transactions and certain other agreements relating to the Entergy System companies’ support of System Energy (including the Capital Funds Agreement), see the “Grand Gulf-Related Agreements” section of NoteNotes 8 to the financial statements and the “Sale and Leaseback Transactions” section of Note 10 to the financial statements and the “Utility - System Energy and Related Agreements” section of Part I, Item 1.
(Entergy Corporation)
As a holding company, Entergy Corporation depends on cash distributions from its subsidiaries to meet its debt service and other financial obligations and to pay dividends on its common stock.
Entergy Corporation is a holding company with no material revenue generating operations of its own or material assets other than the stock of its subsidiaries. Accordingly, all of its operations are conducted by its subsidiaries. Entergy Corporation’s ability to satisfy its financial obligations, including the payment of interest and principal on its outstanding debt, and to pay dividends on its common stock depends on the payment to it of dividends
Part I Item 1A & 1B
Entergy Corporation, Utility operating companies, and System Energy
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, 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 agreementsarticles of incorporation of certain of Entergy Corporation’s subsidiaries restrict the payment of cash dividends to Entergy Corporation. For further information regarding dividend or distribution restrictions to Entergy Corporation, see the “Retained Earnings and Dividend Restrictions” section of Note 7 to the financial statements.
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ENTERGY ARKANSAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2016 Compared to 2015
Net income increased $92.9 million primarily due to higher net revenue and lower other operation and maintenance expenses, partially offset by a higher effective income tax rate and higher depreciation and amortization expenses.
2015 Compared to 2014
Net income decreased $47.1 million primarily due to higher other operation and maintenance expenses, partially offset by higher net revenue.
2014Net Revenue
2016 Compared to 20132015
Net income decreased $40.6 millionrevenue 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 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $1,362.2 |
|
| Retail electric price | 161.5 |
|
| Other | (3.2 | ) |
| 2016 net revenue |
| $1,520.5 |
|
The retail electric price variance is primarily due to higher other operationan increase in base rates, as approved by the APSC. The new base rates were effective February 24, 2016 and maintenance expenses, lower other income, higher depreciation and amortization expenses, and a higherbegan billing with the first billing cycle of April 2016. The increase includes an interim base rate adjustment surcharge, effective income taxwith the first billing cycle of April 2016, to recover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. A significant portion of the increase is related to the purchase of Power Block 2 of the Union Power Station. See Note 2 to the financial statements for further discussion of the rate partially offset by higher net revenue.case. See Note 14 to the financial statements for further discussion of the Union Power Station purchase.
Net Revenue
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
| 2014 net revenue |
| $1,335.9 |
|
| Volume/weather | 12.7 |
|
| Retail electric price | 9.4 |
|
| Asset retirement obligation | 4.2 |
|
| Net wholesale revenue | (7.8 | ) |
| Other | 7.8 |
|
| 2015 net revenue |
| $1,362.2 |
|
The volume/weather variance is primarily due to an increase of 110 GWh, or 1%, in billed electricity usage, including the effect of more favorable weather on residential and commercial sales and an increase in industrial usage. The increase in industrial usage is primarily due to increased demand by existing customers primarily in the petroleum refining and primary metals industries.
The retail electric price variance is primarily due to an increase in the energy efficiency rider, as approved by the APSC, effective July 2014 and July 2015. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income.
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory charge or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of an increase in accretion expense.
The net wholesale revenue variance is primarily due to lower prices.
Other Income Statement Variances
2016 Compared to 2015
Nuclear refueling outage expenses increased primarily due to the amortization of higher costs associated with the most recent outages as compared to the previous outages.
Other operation and maintenance expenses decreased primarily due to:
300a decrease of $21.6 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
the deferral of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance, as approved by the APSC as part of the 2015 rate case settlement. These costs are being amortized over a ten-year period beginning March 2016. See Note 2 to the financial statements for further discussion of the rate case settlement; and
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The net wholesale revenue variance is primarily due to lower prices.
2014 Compareda decrease of $7.2 million in energy efficiency costs, including the effects of true-ups to 2013
Net revenue consiststhe energy efficiency filings for fixed costs to be collected from customers and incentives recognized as a result 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 changeparticipation in net revenue comparing 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $1,301.5 |
|
Retail electric price | 43.3 |
|
Reserve equalization | 16.5 |
|
Transmission revenue | 13.7 |
|
Asset retirement obligation | 12.7 |
|
MISO deferral | (11.1 | ) |
Volume/weather | (13.0 | ) |
Net wholesale revenue | (20.5 | ) |
Other | (7.2 | ) |
2014 net revenue |
| $1,335.9 |
|
energy efficiency programs.
The retail electric price variance isdecrease was partially offset by an increase of $24.1 million in nuclear generation expenses primarily due to an overall higher scope of work done during plant outages and higher nuclear labor costs as compared to prior year and an increase of $8.2 million in fossil-fueled generation expenses primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower residential and commercial revenues as compared to the prior year and a decrease in payroll taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Block 2 of the Union Power Station purchased in March 2016.
Interest expense increased primarily due to:
$5.1 million in estimated interest expense recorded in connection with the FERC orders issued in April 2016 in the energy efficiency rider, as approved by the APSC, effective July 2013 and July 2014, and the effect of the APSC’s order in the 2013 rate case, including an annual base rate increase effective January 2014, offset by a MISO rider to provide customers credits in rates for transmission revenue received through MISO. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have minimal effect on net income.opportunity sales proceeding. See Note 2 to the financial statements for further discussion of the rate case.opportunity sales proceeding; and
The reserve equalization variance is primarily duethe net issuance of $230 million of first mortgage bonds in 2016. See Note 5 to the absencefinancial statements for details of reserve equalization expenses as compared to 2013 resulting from Entergy Arkansas’s exit from the System Agreement.
The transmission revenue variance is primarily due to changes as a result of participation in the MISO RTO in 2014.
The asset retirement obligation affects net revenue because Entergy Arkansas records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings.
The MISO deferral variance is due to the deferral in April 2013, as approved by the APSC, of costs incurred
from March 2010 through December 2012 related to the transition and implementation of joining the MISO RTO.
The volume/weather variance is primarily due to a decrease in sales volume during the unbilled sales period, partially offset by an increase of 190 GWh, or 1%, in billed electricity usage primarily in the residential sector.
The net wholesale revenue variance is primarily due to lower margins on co-owner contracts due to contract changes.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Varianceslong-term debt.
2015 Compared to 2014
Nuclear refueling outage expenses increased primarily due to the amortization of higher expenses associated with the refueling outages at ANO 1 and 2.
Other operation and maintenance expenses increased primarily due to:
an increase of $43.4 million in nuclear generation expenses primarily due to an increase in regulatory compliance costs. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s Reactor Oversight Process Action Matrix. See “ANO Damage, Outage, and NRC Reviews” below for further discussion;
an increase of $15.3 million in distribution expenses primarily due to vegetation maintenance and higher labor costs;
an increase of $12.6 million in energy efficiency costs, including the effects of true-ups to the energy efficiency filings for fixed costs to be collected from customers. Energy efficiency costs are recovered through the energy efficiency rider and have a minimal effect on net income;customers;
an increase of $8.9 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and
an increase of $6.6 million in fossil-fueled generation expenses due to an overall higher scope of work in 2015 as compared to 2014.
The increase was partially offset by a decrease of $6.5 million related to incentives recognized as a result of participation in energy efficiency programs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Taxes other than income taxes increased primarily due to an increase in local franchise taxes resulting from higher residential and commercial revenues in 2015 as compared to 2014, an increase in payroll taxes, and an increase in ad valorem taxes resulting from higher assessments.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Other income increased primarily due to an increase in the allowance for equity funds used during construction resulting from increased transmission spending in 2015 as compared to 2014.
Interest expense increased primarily due to the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014, partially offset by an increase in the allowance for borrowed funds used during construction resulting from increased transmission spending in 2015 as compared to 2014.
2014 Compared to 2013
Other operation and maintenance expenses increased primarily due to:
a net increase of $26.4 million in energy efficiency costs, including a $4.3 million true-up to the 2013 energy efficiency filing for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;
an increase of $21.2 million in nuclear generation expenses primarily due to higher material costs, higher nuclear labor costs, including contract labor, and higher NRC fees;
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
an increase of $13.9 million due to an increase in storm damage accruals effective January 2014, as approved by the APSC;
an increase of $7.5 million in administration fees in 2014 related to participation in the MISO RTO;
an increase of $7.2 million due to the amortization in 2014 of human capital management costs that were deferred in 2013, as approved by the APSC. See Note 2 to the financial statements for further discussion of the deferral of these costs;
an increase of $5.2 million due to the amortization in 2014 of costs deferred in 2013 related to the transition and implementation of joining the MISO RTO; and
the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.2 million of spent nuclear fuel storage costs previously recorded as other operation and maintenance expense.
The increase was partially offset by:
a decrease of $20.8 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
a decrease of $9 million resulting from costs incurred in 2013 related to the generator stator incident at ANO, including an offset for insurance proceeds. See “ANO Damage, Outage, and NRC Reviews” below for further discussion of the incident; and
a decrease of $8.6 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.
Depreciation and amortization expenses increased primarily due to additions to plant in service, higher depreciation rates in 2014, as approved by the APSC, and the effects of recording the final court decision in 2013 in the Entergy Arkansas lawsuit against the U.S. Department of Energy related to spent nuclear fuel disposal. The damages awarded include the reimbursement of approximately $3.6 million of spent nuclear fuel storage costs previously recorded as depreciation expense.
Other income decreased primarily due to lower earnings in 2014 on decommissioning trust fund investments. There is no effect on net income as the trust fund earnings are offset by a corresponding amount of regulatory charges.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014 and 2013 were 39.2%, 35.3%, 40.8%, and 36.2%40.8%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
ANO Damage, Outage, and NRC Reviews
OnIn March 31, 2013, during a scheduled refueling outage at ANO 1, a contractor-owned and operated heavy-lifting apparatus collapsed while moving the generator stator out of the turbine building. The collapse resulted in the death of an ironworker and injuries to several other contract workers, caused ANO 2 to shut down, and damaged the ANO turbine building. The turbine building serves both ANO 1 and 2 and is a non-radiological area of the plant. ANO 2 reconnected to the grid on April 28, 2013 and ANO 1 reconnected to the grid on August 7, 2013. The total cost of assessment, restoration of off-site power, site restoration, debris removal, and replacement of damaged property and equipment was approximately $95 million. Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. During 2014, Entergy Arkansas collected $50 million from Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants. Litigation remains pending.
In addition, Entergy Arkansas incurred replacement power costs for ANO 2 power during its outage and incurred incremental replacement power costs for ANO 1 power because the outage
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
extended beyond the originally-planned duration of the refueling outage. In February 2014 the APSC approved Entergy Arkansas’s request to exclude from the calculation of its revised energy cost rate $65.9 million of deferred fuel and purchased energy costs incurred in 2013 as a result of the ANO stator incident. The APSC authorized Entergy Arkansas to retain the $65.9 million in its deferred fuel balance with recovery to be reviewed in a later period after more information regarding various claims associated with the ANO stator incident is available.
Entergy Arkansas is pursuing its options for recovering damages that resulted from the stator drop, including its insurance coverage and legal action. Entergy is a member of Nuclear Electric Insurance Limited (NEIL), a mutual insurance company that provides property damage coverage to the members’ nuclear generating plants, including ANO. NEIL has notified Entergy that it believes that a $50 million course of construction sublimit applies to any loss associated with the lifting apparatus failure and stator drop at ANO. Entergy has responded that it disagrees with NEIL’s position and is evaluating its options for enforcing its rights under the policy. During 2014, Entergy Arkansas collected $50 million from NEIL and is pursuing additional recoveries due under the policy. In July 2013, Entergy Arkansas filed a complaint in the Circuit Court in Pope County, Arkansas against the owner of the heavy-lifting apparatus that collapsed, an engineering firm, a contractor, and certain individuals asserting claims of breach of contract, negligence, and gross negligence in connection with their responsibility for the stator drop.
Shortly after the stator incident, the NRC deployed an augmented inspection team to review the plant’s response. In July 2013 a second team of NRC inspectors visited ANO to evaluate certain items that were identified as requiring follow-up inspection to determine whether performance deficiencies existed. In March 2014 the NRC issued an inspection report on the follow-up inspection that discussed two preliminary findings, one that was preliminarily determined to be “red with high safety significance” for Unit 1 and one that was preliminarily determined to be “yellow with substantial safety significance” for Unit 2, with the NRC indicating further that these preliminary findings may warrant additional regulatory oversight. This report also noted that one additional item related to flood barrier effectiveness was still under review.
In May 2014 theMarch 2015, after several NRC met with Entergy during ainspections and regulatory conference to discuss the preliminary red and yellow findings and Entergy’s response to the findings. During the regulatory conference, Entergy presented information on the facts and assumptions the NRC used to assess the potential findings. The NRC used the information provided by Entergy at the regulatory conference to finalize its decision regarding the inspection team’s findings. In a letter dated June 23, 2014, the NRC classified both findings as “yellow with substantial safety significance.” In an assessment follow-up letter for ANO dated July 29, 2014, the NRC stated that given the two yellow findings, it determined that the performance at ANO is in the “degraded cornerstone column,” or column 3, of the NRC’s reactor oversight process action matrix beginning the first quarter 2014. Corrective actions in response to the NRC’s findings have been taken and remain ongoing at ANO.
In September 2014 the NRC issued an inspection report on the flood barrier effectiveness issue that was still under review at the time of the March 2014 inspection report. While Entergy believes that the flood barrier issues that led to the finding have been addressed at ANO, NRC processes still required that the NRC assess the safety significance of the deficiencies. In its September 2014 inspection report, the NRC discussed a preliminary finding of “yellow with substantial safety significance” for the Unit 1 and Unit 2 auxiliary and emergency diesel fuel storage buildings. The NRC indicated that these preliminary findings may warrant additional regulatory oversight. Entergy requested a public regulatory conference regarding the inspection, and the conference was held in October 2014. During the regulatory conference, Entergy presented information related to the facts and assumptions used by the NRC in arriving at its preliminary finding of “yellow with substantial safety significance.” In January 2015 the NRC issued its final risk significance determination for the flood barrier violation originally cited in the September 2014 report. The NRC’s final risk significance determination was classified as “yellow with substantial safety significance.”
In March 2015conferences, the NRC issued a letter notifying Entergy of its decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4)column,” or Column 4, of the NRC’s Reactor Oversight Process Action Matrix. Placement into Column 4 requires significant additional NRC inspection activities at the ANO site, including a review of the site’s root cause evaluation associated with the flood barrier and stator issues, an assessment of the effectiveness of the site’s
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
effectiveness and stator issues, an assessment of the effectiveness of the site’s corrective action program, an additional design basis inspection, a safety culture assessment, and possibly other inspection activities consistent with the NRC’s Inspection Procedure. Entergy Arkansas incurred incremental costs of approximately $53 million in 2015 to prepare for the NRC inspection that began in early 2016. Excluding remediation and response costs that may result from the additional NRC inspection activities, Entergy Arkansas also expects to incurincurred approximately $50$44 million in 2016 in support of NRC inspection activities and to implement Entergy Arkansas’s performance improvement initiatives developed in 2015. A much lesser amount of incremental expensesexpense is expected to be ongoing annually after 2016.2016, until ANO transitions out of Column 4.
The NRC completed the supplemental inspection required for ANO’s Column 4 designation in February 2016, and published its inspection report in June 2016. In its inspection report, the NRC concluded that the ANO site is being operated safely and that Entergy understands the depth and breadth of performance concerns associated with ANO’s performance decline. Also in June 2016, the NRC issued a confirmatory action letter to confirm the actions Entergy Arkansas has taken and will continue to take to improve performance at ANO. The NRC will verify the completion of those actions through quarterly follow-up inspections, the results of which will determine when ANO should transition out of Column 4.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, 2014, and 20132014 were as follows:
| | | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 | |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $218,505 |
| |
| $127,022 |
| |
| $34,533 |
| |
| $9,135 |
| |
| $218,505 |
| |
| $127,022 |
| |
| | | | | | | | | | | | | |
| Net cash provided by (used in): | | | |
| | |
| | | | |
| | |
| |
| Operating activities | 474,890 |
| | 403,826 |
| | 401,250 |
| | 676,511 |
| | 474,890 |
| | 403,826 |
| |
| Investing activities | (685,274 | ) | | (600,628 | ) | | (524,473 | ) | | (947,995 | ) | | (685,274 | ) | | (600,628 | ) | |
| Financing activities | 1,014 |
| | 288,285 |
| | 215,712 |
| | 282,858 |
| | 1,014 |
| | 288,285 |
| |
| Net increase (decrease) in cash and cash equivalents | (209,370 | ) | | 91,483 |
| | 92,489 |
| | 11,374 |
| | (209,370 | ) | | 91,483 |
| |
| | | | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $9,135 |
| |
| $218,505 |
| |
| $127,022 |
| |
| $20,509 |
| |
| $9,135 |
| |
| $218,505 |
| |
Operating Activities
Net cash flow provided by operating activities increased $201.6 million in 2016 primarily due to:
income tax refunds of $135.7 million in 2016 compared to income tax payments of $103.3 million in 2015. Entergy Arkansas had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits;
the timing of payments to vendors; and
an increase in net revenue.
The increase was partially offset by a decrease due to the timing of recovery of fuel and purchased power costs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow provided by operating activities increased $71.1 million in 2015 primarily due to:
a $68 million payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $38 million payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. In 2015, Entergy Arkansas received $89.5 million in System Agreement bandwidth remedy collections from customers related to the filings. See Note 2 to the financial statements for a discussion of the System Agreement proceedings and related recovery from customers;
an increase indue to the timing of recovery of fuel and purchased power costs; and
a decrease of $50 million in storm spending in 2015.
The increase was partially offset by:
income tax payments of $103.3 million in 2015 compared to income tax refunds of $48.9 million in 2014. Entergy Arkansas made income tax payments in 2015 and received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 resulted primarily from final settlement of amounts outstanding associated with the 2006-2007 IRS audit as well as adjustments associated with the settlement of the 2008-2009 IRS audit whereas the income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group. See Note 3 to the financial statements for a discussion of the income tax audits;
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
an increase in nuclear generation expenses primarily due to an increase in regulatory compliance costs. The increase in regulatory compliance costs is primarily related to additional NRC inspection activities in 2015 as a result of the NRC’s March 2015 decision to move ANO into the “multiple/repetitive degraded cornerstone column” of the NRC’s Reactor Oversight Process Action Matrix. See “ANO Damage, Outage, and NRC Reviews” above; and
an increase of $30 million in spending on nuclear refueling outages in 2015.
Net cash flow provided by operating activities increased $2.6 million in 2014 primarily due to:
income tax refunds of $48.9 million in 2014 compared to income tax payments of $184.6 million in 2013. Entergy Arkansas received income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2014 resulted primarily from the utilization of Entergy Arkansas’s net operating losses by the consolidated group whereas the income tax payments in 2013 resulted primarily from the reversal of temporary differences for which Entergy Arkansas had previously claimed a tax deduction;
approximately $25 million in spending in 2013 related to the generator stator incident at ANO, as discussed
above; and
$13.4 million in insurance proceeds received in 2014 for property damages related to the generator stator
incident at ANO, as discussed above.
The increase was partially offset by:
a decrease in the recovery of fuel and purchased power costs including a $68 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period and a $38 million System Agreement bandwidth remedy payment made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the comprehensive recalculation for 2007, 2008, and 2009. See Note 2 to the financial statements for a discussion of the System Agreement bandwidth remedy payments;
an increase of $60.1 million in pension contributions in 2014. See “Critical Accounting Estimates”below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding;
proceeds of $38 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel;
the timing of payments to vendors; and
an increase of $24.6 million in storm spending in 2014.
Investing Activities
Net cash flow used in investing activities increased $262.7 million in 2016 primarily due to the purchase of Power Block 2 of the Union Power Station in March 2016 for approximately $237 million. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The increase was partially offset by the 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 service deliveries, and the timing of cash payments during the nuclear fuel cycle.
Net cash flow used in investing activities increased $84.6 million in 2015 primarily due to:
an increase in transmission construction expenditures primarily due to a higher scope of non-storm related work performed in 2015;
an increase in nuclear construction expenditures primarily due to a higher scope of work on various nuclear projects in 2015 as compared to 2014 and compliance with NRC post-Fukushima requirements;
an increase in distribution construction expenditures due to a higher scope of work performed in 2015;
an increase in information technology capital expenditures due to various technology projects and upgrades in 2015;
$11.7 million in insurance proceeds received in 2015 compared to $36.6 million received in 2014 for property damages related to the generator stator incident at ANO, as discussed above; and
money pool activity.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
a decrease in transmission and distribution construction expenditures primarily due to higher storm restoration spending in 2014; and
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.
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 $2.2 million in 2015 compared to decreasing by $15.3 million in 2014. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Net cash used in investingflow provided by financing activities increased $76.2$281.8 million in 20142016 primarily due to:
an increasethe net issuance of $101.4$189.1 million storm spendingof long-term debt in 2014;2016 compared to the net retirement of $13.2 million of long-term debt in 2015;
fluctuationsa $200 million capital contribution received from Entergy Corporation in March 2016 primarily in anticipation of Entergy Arkansas’s purchase of Power Block 2 of the Union Power Station; and
net repayments of $11.7 million on the Entergy Arkansas nuclear fuel activity becausecompany variable interest entity credit facility in 2016 compared to net repayments of variations from year to year$36.3 million 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; and
proceeds of $10.3 million received in 2013 from the U.S. Department of Energy resulting from litigation regarding the storage of spent nuclear fuel.2015.
The decreaseincrease was partially offset by:
approximately $69by the redemption of $75 million of 6.45% Series preferred stock in spending2016, the redemption of $10 million of 6.08% Series preferred stock in 2013 related to the generator stator incident at ANO, as discussed above;
$36.6 million in insurance proceeds received in 2014 for property damages related to the generator stator incident at ANO, as discussed above;2016, and
money pool activity.
Decreases in Entergy Arkansas’s receivable frompayable to the money pool are a sourceuse of cash flow, and Entergy Arkansas’s receivable frompayable to the money pool decreased by $15.3$1.5 million in 20142016 compared to increasing by $9.5$52.7 million in 2013.
Financing Activities2015.
Net cash flow provided by financing activities decreased $287.3 million in 2015 primarily due to:
the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;
the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;
net repayments of $36.3 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2015 compared to net borrowings of $48 million in 2014; and
the issuance of $375 million of 3.7% Series first mortgage bonds in March 2014, the proceeds of which were used to pay, prior to maturities, a $250 million term loan in March 2014 and $115 million of 5.0% Series first mortgage bonds in April 2014.
The decrease was partially offset by:
the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014;
money pool activity; and
a decrease of $10 million in common stock dividends paid in 2015 in anticipation of the purchase of Power Block 2 of the Union Power Station.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
money pool activity; and
$10 million in common stock dividends paid in 2014.
Increases in Entergy Arkansas’s payable to the money pool are a source of cash flow, and Entergy Arkansas’s payable to the money pool increased by $52.7 million in 2015.
Net cash provided by financing activities increased $72.6 million in 2014 primarily due to:
the issuance of $375 million of 3.70% Series first mortgage bonds in March 2014;
the retirement, at maturity, of $300 million of 5.40% Series first mortgage bonds in August 2013;
the issuance of $90 million of 9% Series L notes by the nuclear fuel company variable interest entity in July 2014;
the issuance of $250 million of 4.95% Series first mortgage bonds in December 2014;
net borrowings of $48 million on the Entergy Arkansas nuclear fuel company variable interest entity credit facility in 2014 compared to net repayments of $36.7 million in 2013;
the retirement, at maturity, of $30 million of 9% Series H notes by the nuclear fuel company variable interest entity in June 2013; and
a decrease of $5 million in common stock dividends paid in 2014.
The increase was partially offset by:
borrowings on a $250 million term loan credit facility entered into in July 2013 and its repayment, prior to maturity, in March 2014;
the issuance of $250 million of 3.05% Series first mortgage bonds in May 2013;
the issuance of $125 million of 4.75% Series first mortgage bonds in June 2013;
the retirement, prior to maturity, of $115 million of 5.0% Series first mortgage bonds in April 2014; and
the retirement, at maturity, of $70 million of 5.69% Series I notes by the nuclear fuel company variable interest entity in July 2014.
See Note 5 to the financial statements for details of long-term debt.
Capital Structure
Entergy Arkansas’s capitalization is balanced between equity and debt, as shown in the following table. The
decrease in the debt to capital ratio for Entergy Arkansas is primarily due to an increasethe capital contribution received from Entergy Corporation in retained earnings.March 2016, partially offset by the issuance of long-term debt in 2016 and the redemption of $75 million of 6.45% Series preferred stock and $10 million of 6.08% Series preferred stock, as discussed above.
| | | | December 31,
2015 | | December 31,
2014 | December 31,
2016 | | December 31,
2015 |
| Debt to capital | 56.8% | | 58.1% | 55.3% | | 56.8% |
| Effect of excluding the securitization bonds | (0.6%) | | (0.7%) | (0.4%) | | (0.6%) |
| Debt to capital, excluding securitization bonds (a) | 56.2% | | 57.4% | 54.9% | | 56.2% |
| Effect of subtracting cash | (0.1%) | | (2.1%) | (0.2%) | | (0.1%) |
| Net debt to net capital, excluding securitization bonds (a) | 56.1% | | 55.3% | 54.7% | | 56.1% |
| |
| (a) | 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 short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Arkansas uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because the securitization bonds are non-recourse to Entergy Arkansas, as more fully described in Note 5 to the financial statements. Entergy Arkansas also
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Arkansas’s financial condition because net debt indicates Entergy Arkansas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Arkansas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Arkansas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Arkansas may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Arkansas requires capital resources for:
construction and other capital investments;
debt and preferred stock maturities or retirements;
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Arkansas’s planned construction and other capital investments.
| | | | 2016 | | 2017 | | 2018 | 2017 | | 2018 | | 2019 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | |
| | |
| | | |
| | |
|
| Generation |
| $395 |
| |
| $135 |
| |
| $135 |
|
| $235 |
| |
| $190 |
| |
| $240 |
|
| Transmission | 175 |
| | 185 |
| | 125 |
| 145 |
| | 140 |
| | 140 |
|
| Distribution | 210 |
| | 240 |
| | 200 |
| 215 |
| | 210 |
| | 225 |
|
| Other | 65 |
| | 30 |
| | 45 |
| 115 |
| | 80 |
| | 50 |
|
| Total |
| $845 |
| |
| $590 |
| |
| $505 |
|
| $710 |
| |
| $620 |
| |
| $655 |
|
Following are the amounts of Entergy Arkansas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2016 | | 2017-2018 | | 2019-2020 | | after 2020 | | Total | 2017 | | 2018-2019 | | 2020-2021 | | after 2021 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $160 |
| |
| $319 |
| |
| $202 |
| |
| $3,848 |
| |
| $4,529 |
|
| $233 |
| |
| $233 |
| |
| $681 |
| |
| $4,046 |
| |
| $5,193 |
|
| Operating leases |
| $25 |
| |
| $32 |
| |
| $21 |
| |
| $28 |
| |
| $106 |
|
| $18 |
| |
| $30 |
| |
| $15 |
| |
| $26 |
| |
| $89 |
|
| Purchase obligations (b) |
| $620 |
| |
| $915 |
| |
| $539 |
| |
| $1,095 |
| |
| $3,169 |
|
| $523 |
| |
| $654 |
| |
| $513 |
| |
| $4,740 |
| |
| $6,430 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | 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 are discussed in Note 8 to the financial statements. |
In addition to the contractual obligations given above, Entergy Arkansas currently expects to contribute approximately $82.8$79.4 million to its qualified pension plans and approximately $4.2 million$525 thousand to its other postretirement health care and life insurance plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017. 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 Arkansas has $21.8$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.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Arkansas includes specific investments, such as the Union Power Station acquisition discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintainenhance reliability and improve service to customers, including initial investment to support smart meter deployment;advanced metering; resource planning, including potential generation projects; system improvements; investments in the nuclear fleet, as discussed below in “Nuclear Matters;” and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints requirements, and oversight,requirements, environmental compliance, business opportunities, 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 Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary,discussed above in “Capital Structure,” Entergy Arkansas paysroutinely evaluates its ability to pay dividends to Entergy Corporation from its earnings at a percentage determined monthly.earnings. Provisions in Entergy Arkansas’s long-term debt indenture restrictsarticles of incorporation relating to preferred
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
stock restrict 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, 2015, Entergy Arkansas had restricted retained earnings unavailable for distribution to Entergy Corporation of $394.9 million.
Union Power Station Purchase Agreement
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana would acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas would each acquire one power block and a 25% undivided ownership interest in such related assets. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. Under the original terms of the asset purchase agreement, these included regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino antitrust law.
In December 2014, Entergy Texas filed its application for Certificate of Convenience and Necessity (CCN) with the PUCT seeking one of the two necessary PUCT approvals of the acquisition. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the CCN filing. In July 2015, Entergy Texas withdrew its rate case and, together with other parties, filed a motion with the PUCT to dismiss Entergy Texas’s CCN application. In July 2015, the PUCT granted the motion to dismiss the CCN case. The power block originally allocated to Entergy Texas will be acquired by Entergy New Orleans. The acquisition by Entergy New Orleans replaces the power purchase agreement with Entergy Gulf States Louisiana that the City Council approved in June 2015. In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisition of the power block and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest.
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery. Supplemental testimony was submitted in July 2015 explaining the reallocation of one of the power blocks to Entergy New Orleans and clarifying that Entergy Gulf States Louisiana would own 100% of the capacity and associated energy of two power blocks. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
In January 2015, Entergy Arkansas filed its application with the APSC for approval of the acquisition and cost recovery. A hearing was held in September 2015. In November 2015 the APSC issued an order conditionally approving the acquisition and requesting that Entergy Arkansas file compliance testimony reporting on two minor conditions. In January 2016 the APSC issued an order finding that Entergy Arkansas’s December 2015 compliance filing was substantially compliant with its November 2015 order. If the transaction closes on or before March 24, 2016, recovery of the costs to acquire Power Block 2 of the Union Power Station will be through Entergy Arkansas’s new base rates that will commence with the first billing cycle of April 2016. If the transaction closes after that date, the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.
In February 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed a notification and report form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act with the United States Department of Justice (DOJ) and Federal Trade Commission with respect to their planned acquisition of the Union Power Station. Union Power Partners, L.P. (UPP), the seller, also filed a notification and report form in February 2015.
In March 2015 the DOJ requested additional information and documentary material from each of the purchasing companies and UPP. Also in March 2015, UPP, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed an application with the FERC requesting authorization for the transaction. In April 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas made a filing with the FERC for approval of their proposed accounting treatment of the amortization expenses relating to the acquisition adjustment. Filings were made with the FERC in September 2015 replacing Entergy Texas with Entergy New Orleans as an applicant in the filings and providing supplemental information. In the FERC proceeding requesting authorization for the transaction, in December 2015, UPP, Entergy Arkansas, Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, and Entergy New Orleans filed their response to the FERC’s November 2015 request for additional information. The public comment period on the December 2015 filing expired in January 2016. No protests were filed. The LPSC, City Council, and APSC have filed submissions with the FERC urging the FERC to promptly consider and approve the transaction.
Closing of the purchase is expected to be completed promptly following the receipt of FERC approval.
Sources of Capital
Entergy Arkansas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Arkansas may refinance, redeem, or otherwise 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’s corporate charters, bond indentures, and other agreements. Entergy Arkansas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| ($52,742) | | $2,218 | | $17,531 | | $8,035 |
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| ($51,232) | | ($52,742) | | $2,218 | | $17,531 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Arkansas has a credit facility in the amount of $150 million scheduled to expire in August 2020.2021. Entergy Arkansas also has a $20 million credit facility scheduled to expire in April 2016.2017. The $150 million credit facility allows Entergy Arkansas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2015,2016, there were no cash borrowings and no letters of credit outstanding under the credit facilities. In addition, Entergy Arkansas is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2015,2016, a $1 million letter of credit was outstanding under Entergy Arkansas’s uncommitted letter of credit facility. 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$80 million scheduled to expire in June 2016.May 2019. As of December 31, 2015, $11.7 million in2016, no letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the Entergy Arkansas nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Arkansas obtained authorizations from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $250 million at any time outstanding and long-term borrowings by its nuclear fuel company variable interest entity. See Note 4 to the financial statements for further discussion of Entergy Arkansas’s short-term borrowing limits. The long-term securities issuances of Entergy Arkansas are limited to amounts authorized by the APSC and the Tennessee Regulatory Authority; the current authorizations extend through December 2018.
Entergy Arkansas, issued $325 million of 3.5% Series first mortgage bonds due April 2026. Entergy Arkansas used the proceeds to pay, prior to maturity, its $175 million of 5.66% Series first mortgage bonds due February 2025,Inc. and expects to use the remainder of the proceeds, together with other funds, towards the purchase of a power block at the Union Power StationSubsidiaries
Management’s Financial Discussion and for general corporate purposes. See “Union Power Station Purchase Agreement” above for additional discussion of the Union acquisition.Analysis
State and Local Rate Regulation and Fuel-Cost Recovery
Retail Rates
2013 Base Rate Filing
In March 2013, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing assumed Entergy Arkansas’s transition to MISO in December 2013, and requested a rate increase of $174 million, including $49 million of revenue being transferred from collection in riders to base rates. The filing also proposed a new transmission rider and a capacity cost recovery rider. The filing requested a 10.4% return on common equity. In September 2013, Entergy Arkansas filed testimony reflecting an updated rate increase request of $145 million, with no change to its requested return on common equity of 10.4%. Hearings in the proceeding began in October 2013, and in December 2013 the APSC issued an order. The order authorized a base rate increase of $81 million and included an authorized return on common equity of 9.3%. The order allowed Entergy Arkansas to amortize its human capital management costs over a three-and-a-half year period, but also ordered Entergy Arkansas to file a detailed report ofperiod. New rates under the Arkansas-specific costs, savings, and final payroll changes upon conclusion of the human capital management
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
strategic imperative. The detailed report was subsequently filed in February 2015. The substance of the report was addressed in Entergy Arkansas’s 2015 base rate filing. New ratesJanuary 2014 order were implemented in the first billing cycle of March 2014 and were effective as of January 2014. Additionally, in January 2014, Entergy Arkansas filed a petition for rehearing or clarification of several aspects of the APSC’s order, including the 9.3% authorized return on common equity. In February 2014 the APSC granted Entergy Arkansas’s petition for the purpose of considering the additional evidence identified by Entergy Arkansas. In August 2014 the APSC issued an order amending certain aspects of the original order, including providing for a 9.5% authorized return on common equity. Pursuant to the August 2014 order, revised rates were effective for all bills rendered after December 31, 2013 and were implemented in the first billing cycle of October 2014.
2015 Base Rate Filing
In April 2015, Entergy Arkansas filed with the APSC for a general change in rates, charges, and tariffs. The filing notified the APSC of Entergy Arkansas’s intent to implement a forward test year formula rate plan pursuant to Arkansas legislation passed in 2015, and requested a retail rate increase of $268.4 million, with a net increase in revenue of $167 million. The filing requested a 10.2% return on common equity. In MaySeptember 2015 the APSC issued an order suspending the proposed rates and tariffs filed by Entergy Arkansas and establishing a procedural schedule to complete its investigation of Entergy Arkansas’s application. In September 2015, APSC staff and intervenors filed direct testimony, with the APSC staff recommending a revenue requirement of $217.9 million and a 9.65% return on common equity. Entergy Arkansas filed rebuttal testimony in October 2015. In December 2015, Entergy Arkansas, the APSC staff, and certain of the intervenors in the rate case filed with the APSC a joint motion for approval of a settlement of the case that proposesproposed a retail rate increase of approximately $225 million with a net increase in revenue of approximately $133 million; an authorized return on common equity of 9.75%; and a formula rate plan tariff that provides a +/- 50 basis point band around the 9.75% allowed return on common equity.
A significant portion of the rate increase is related to Entergy Arkansas’s acquisition in March 2016 of Union Power Station Power Block 2 for a base purchase price of $237 million. The settlement agreement also provided for amortization over a 10-year period of $7.7 million of previously-incurred costs related to ANO post-Fukushima compliance and $9.9 million of previously-incurred costs related to ANO flood barrier compliance. A settlement hearing was held in January 2016. In February 2016 the APSC approved the settlement with one exception that would reducereduced the retail rate increase proposed in the settlement by $5 million. The settling parties were directedagreed to inform the APSC by filing no later thanmodifications in February 26,2016. The new rates were effective February 24, 2016 whether they acceptand began billing with the APSC’s proposed settlement agreement modification or request a full hearing on the issues.first billing cycle of April 2016. In March 2016, Entergy Arkansas plansmade a compliance filing regarding the new rates that included an interim base rate adjustment surcharge, effective with the first billing cycle of April 2016, to makerecover the incremental revenue requirement for the period February 24, 2016 through March 31, 2016. The interim base rate adjustment surcharge was designed to recover a total of $21.1 million over the nine-month period from April 2016 through December 2016.
2016 Formula Rate Plan Filing
In July 2016, Entergy Arkansas filed with the APSC its first2016 formula rate plan filing in Julyshowing Entergy Arkansas’s projected earned return on common equity for the twelve months ended December 31, 2017 test period to be below the formula rate plan bandwidth. The filing requested a $67.7 million revenue requirement increase to achieve
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy Arkansas’s target earned return on common equity of 9.75%. In October 2016, Entergy Arkansas filed with the APSC revised formula rate plan attachments with an updated request for a $54.4 million revenue requirement increase based on acceptance of certain adjustments and recommendations made by the APSC staff and other intervenors, as well as three additional adjustments identified as appropriate by Entergy Arkansas. In November 2016 a hearing was held and the APSC issued an order directing the parties to brief certain issues. In December 2016 the APSC approved the settlement agreement and the $54.4 million revenue requirement increase with approximately $25 million of the $54.4 million revenue requirement subject to possible future adjustment and refund to customers with interest. The APSC requested supplemental information for some of Entergy Arkansas’s requested nuclear expenditures. The APSC indicated that a procedural schedule would be set by subsequent order to obtain the additional information. In December 2016 the APSC approved Entergy Arkansas’s formula rate plan compliance tariff, and the rates became effective with the first billing cycle of January 2017.
A significant portion ofAdvanced Metering Infrastructure (AMI) Filing
In September 2016, Entergy Arkansas filed an application seeking an order from the rate increase is related toAPSC finding that Entergy Arkansas’s acquisitiondeployment of Union Power Station Power Block 2 for an expected base purchase priceAMI is in the public interest. Entergy Arkansas proposed to replace existing meters with advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of $237 million, subject to adjustment.Entergy Arkansas’s modernized power grid. The acquisitionfiling identified a number of quantified and unquantified benefits, and Entergy Arkansas provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal net benefit to customers of $431 million. Entergy Arkansas also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $57 million, of existing meters that will be completed promptly following the receipt of FERC approval. If the acquisition closes on or before March 24, 2016, recoveryretired as part of the costsAMI deployment and also to acquire Power Block 2depreciate those assets using current depreciation rates. Entergy Arkansas proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the APSC, deployment of the Union Power Station will be throughcommunications network is expected to begin in 2018. Entergy Arkansas’s new base ratesArkansas proposed to include the AMI deployment costs and the quantified benefits in future formula rate plan filings. In order to have certainty around its 2018 projected AMI deployment costs, Entergy Arkansas sought an order from the APSC prior to the hearing on its expected 2017 formula rate plan filing in the fourth quarter 2017. In January 2017 the APSC approved a procedural schedule that will commence with the first billing cycle of April 2016. If the transaction closes after that date, the parties have agreed to concurrent cost recovery through Entergy Arkansas’s capacity acquisition rider.provides for a hearing in August 2017.
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. 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. See Note 2 to the financial statements and Entergy Corporation and Subsidiaries “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - System Agreement” for discussions of the System Agreement proceedings.
In May 2014, Entergy Arkansas filed its annual redetermination of the production cost allocation rider to recover the $3 million unrecovered retail balance as of December 31, 2013 and the $67.8 million System Agreement bandwidth remedy payment made in May 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. In June 2014 the APSC suspended the annual redetermination of the production cost allocation rider and scheduled a hearing in September
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2014. Upon a joint motion of the parties, the APSC canceled the September 2014 hearing and in January 2015 the APSC issued an order approving Entergy Arkansas’s request for recovery of the $3 million under-recovered amount based on the true-up of the production cost allocation rider and the $67.8 million May 2014 System Agreement bandwidth remedy payment subject to refund with interest, with recovery of these payments concluding with the last billing cycle in December 2015. The APSC also found that Entergy Arkansas is entitled to carrying charges pursuant to the current terms of the production cost allocation rider. Entergy Arkansas made its compliance filing pursuant to the order in January 2015 and the APSC issued its approval order, also in January 2015. The redetermined rate went into effect with the first billing cycle of February 2015.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In May 2015, Entergy Arkansas filed its annual redetermination of the production cost allocation rider, which included a $38 million payment made by Entergy Arkansas as a result of the FERC’s February 2014 order related to the comprehensive bandwidth recalculation for calendar year 2006, 2007, and 2008 production costs. The redetermined rate for the 2015 production cost allocation rider update was added to the redetermined rate from the 2014 production cost allocation rider update and the combined rate was effective with the first billing cycle of July 2015. This combined rate was effective through December 2015. The collection of the remainder of the redetermined rate for the 2015 production cost allocation rider update will continuecontinued through June 2016.
In May 2016, Entergy Arkansas filed its annual redetermination pursuant to the production cost allocation rider, which reflected recovery of the production cost allocation rider true-up adjustment of the 2014 and 2015 unrecovered retail balance in the amount of $1.9 million. Additionally, the redetermined rates reflected the recovery of a $1.9 million System Agreement bandwidth remedy payment resulting from a compliance filing pursuant to the FERC’s December 2015 order related to test year 2009 production costs. The rates for the 2016 production cost allocation rider update became effective with the first billing cycle of July 2016, and rates will be effective through June 2017.
Energy Cost Recovery Rider
Entergy Arkansas’s retail rates include an energy cost recovery rider to recover fuel and purchased energy costs in monthly customer bills. The rider utilizes the 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- 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.
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 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 that resulted from two outages caused by employee and contractor error. The coal plant generation curtailments were caused by railroad delivery problems and Entergy Arkansas 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 sixty days of the order. After a final determination of the costs is made by the APSC, Entergy Arkansas will 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 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. The testimony was filed, and the APSC will decide the case based on the record in the proceeding.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
In January 2014, Entergy Arkansas filed a motion with the APSC relating to its redetermination of its energy cost rate that was subsequently filed in March 2014. In that motion, Entergy Arkansas requested that the APSC authorize Entergy Arkansas to exclude $65.9 million of deferred fuel and purchased energy costs incurred in 2013 from the redetermination of its 2014 energy cost rate. The $65.9 million is an estimate of the incremental fuel and replacement energy costs that Entergy Arkansas incurred as a result of the ANO stator incident. Entergy Arkansas requested that the APSC authorize Entergy Arkansas to retain that amount in its deferred fuel balance, with recovery to be reviewed in a later period after more information is available regarding various claims associated with the ANO stator incident. The APSC approved Entergy Arkansas’s request in February 2014. See the “ANO Damage, Outage, and NRC Reviews” section above for further discussion of the ANO stator incident.
Storm Cost Recovery
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 were $63 million, including costs recorded as regulatory assets of approximately $22 million. In the Entergy Arkansas 2013 rate case, the APSC approved inclusion of the construction spending in rate base and approved an increase in the normal storm cost accrual.
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. In July 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 explained thatFERC subsequently ordered a hearing in the FERC already had 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 raised no additional claims or facts that would warrant the FERC reaching a different conclusion.proceeding.
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
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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, excluding interest, and the potential benefit would be significantly less than that for each of the other Utility operating companies. Entergy’s proposed illustrative re-run 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, excluding interest, that should be paid by Entergy Arkansas to the other 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. The FERC staff and certain intervenors filed direct and answering testimony in February 2013. In April 2013, Entergy filed its rebuttal testimony in that proceeding, including a revised illustrative re-run of the intra-system bills for the years 2003, 2004, and 2006. The revised calculation determines the re-pricing of the opportunity sales based on consideration of moveable resources only and the removal of exchange energy received by Entergy Arkansas, which increases the potential cost for Entergy Arkansas over the three years 2003, 2004, and 2006 by $2.3 million from the potential costs identified in the Utility operating companies’ prior filings in September and October 2012. A hearing was held in May 2013 to quantify the effect of repricing the opportunity sales in accordance with the FERC’s decision.
In August 2013 the presiding judge issued an initial decision in the calculation proceeding. The initial decision concludes that the methodology proposed by the LPSC, rather than the methodologies proposed by Entergy or the FERC Staff, should be used to calculate the payments that Entergy Arkansas is to make to the other Utility operating companies. The initial decision also concludes that the other System Agreement service schedules should not be adjusted and that payments by Entergy Arkansas should not be reflected in the rough production cost equalization bandwidth calculations for the applicable years. The initial decision does recognize that the LPSC’s methodology would result in an inequitable windfall to the other Utility operating companies and, therefore, concludes that any payments by Entergy Arkansas should be reduced by 20%. The Utility operating companies are currently analyzing the effects of the initial decision. The LPSC, APSC, City Council, and FERC staff filed briefs on exceptions and/or briefs opposing exceptions. Entergy filed a brief on exceptions requesting that FERC reverse the initial decision and a brief opposing certain exceptions taken by the LPSC and FERC staff.
In April 2016 the FERC issued orders addressing the requests for rehearing filed in July 2012 and the ALJ’s August 2013 initial decision. The first order denies Entergy’s request for rehearing and affirms FERC’s reviewearlier rulings that Entergy’s original methodology for allocating energy costs to the opportunity sales was incorrect and, as a result, Entergy Arkansas must make payments to the other Utility operating companies to put them in the same position that they would have been in absent the incorrect allocation. The FERC clarified that interest should be included with the payments. The second order affirmed in part, and reversed in part, the rulings in the ALJ’s initial decision regarding the methodology that should be used to calculate the payments Entergy Arkansas is to make to the other Utility operating companies. The FERC affirmed the ALJ’s ruling that a full re-run of intra-system bills should be performed, but required that methodology be modified so that the sales have the same priority for purposes of energy allocation as joint account sales. The FERC reversed the ALJ’s decision that any payments by Entergy Arkansas should be reduced by 20%. The FERC also reversed the ALJ’s decision that adjustments to other System Agreement service schedules and excess bandwidth payments should not be taken into account when calculating the payments to be made by Entergy Arkansas. The FERC held that such adjustments and excess bandwidth payments should be taken into account, but ordered further proceedings before an ALJ to address whether a cap on any reduction due to bandwidth payments was necessary and to implement the other adjustments to the calculation methodology.
The effect of the FERC’s decisions, if upheld, is that Entergy Arkansas will make payments to some or all of the other Utility operating companies. As part of the further proceedings required by the FERC, Entergy has performed an initial re-run of the intra-system bills for the ten-year period (2000-2009) to attempt to quantify the effects of the FERC's rulings. The ALJ will issue an initial decision is pending.and FERC will issue an order reviewing that decision. No payments will be made or received by the Utility operating companies until the FERC issues an order reviewing the initial decision and Entergy submits a subsequent filing to comply with that order.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
initial decision and Entergy submits a subsequent filing to comply with that order. Because further proceedings are required, the amount and recipients of payments by Entergy Arkansas are unknown at this time. Based on testimony previously submitted in the case, however, in the first quarter 2016 Entergy Arkansas recorded a liability of $87 million for its estimated increased costs and payment to the other Utility operating companies, including interest. This estimate is subject to change depending on how the FERC resolves the issues that are still outstanding in the case. Entergy Arkansas’s increased costs will be attributed to Entergy Arkansas’s retail and wholesale businesses, and it is not probable that Entergy Arkansas will recover the wholesale portion. Therefore Entergy Arkansas recorded a regulatory asset of approximately $75 million, which represents its estimate of the retail portion of the costs.
In May 2016, Entergy Services filed a request for rehearing of the FERC’s April 2016 order addressing the requests for rehearing filed in July 2012. Entergy Services also filed a request for clarification and/or rehearing of the FERC’s April 2016 order addressing the ALJ’s August 2013 initial decision. The APSC and the LPSC also filed requests for rehearing of the FERC’s April 2016 order. Also, in May 2016 a procedural schedule was established with a hearing in May 2017 and an initial decision expected in August 2017. Pursuant to that procedural schedule, Entergy Services re-ran intra-system bills for the ten-year period to quantify the effects of the FERC’s ruling. The LPSC submitted testimony disputing certain aspects of the calculations, and Entergy Services submitted answering testimony.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization” and “System Agreement” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
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.
In 2016, Entergy conducted a comprehensive evaluation of the Entergy nuclear fleet and determined that it is necessary to increase investments in its nuclear plants to position the fleet to meet its operational goals. These investments will result in increased operating and capital costs associated with operating Entergy’s nuclear plants going forward. The preliminary estimates of the increase to planned capital costs for 2017 through 2019 identified through and associated with this initiative are estimated to be $290 million for Entergy Arkansas. The current estimates of the capital costs identified through this initiative are included in Entergy Arkansas’s preliminary capital investment plan estimate for 2017 through 2019 given in “Liquidity and Capital Resources - Uses of Capital”above. The increase to planned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $35 million in 2017 for Entergy Arkansas, with a similar level of expenses expected to continue going forward. In addition, nuclear refueling outage expenses are expected to increase going forward.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.plant systems. The issue is applicable at all nuclear units to ANOvarying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
After the nuclear incident in Japan resulting from the March 2011 earthquake316
Entergy Arkansas, Inc. and tsunami, the NRC established a task force to conduct a review of processesSubsidiaries
Management’s Financial Discussion 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 to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Arkansas’s estimated capital expenditures for 2016 through 2018 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.Analysis
See “ANO Damage, Outage, and NRC Reviews” above for discussion of the NRC’s decision to move ANO into the “multiple/repetitive degraded cornerstone column” (Column 4) of the NRC’s Reactor Oversight Process Action Matrix, and the resulting significant additional NRC inspection activities at the ANO site.
Environmental Risks
Entergy 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.
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy 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’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.
Utility Regulatory Accounting
In 2014, Entergy Arkansas recorded a revision to its estimated decommissioning cost liabilities for ANO 1 and ANO 2 as a result of a revised decommissioning cost study. The revised estimates resulted in a $47.6 million increaseSee “Utility Regulatory Accounting” in the decommissioning cost liabilities, along with a corresponding increase in“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the related asset retirement cost assets that will be depreciated over the remaining liveseffects of the units.rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy Arkansas records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Taxation and a receivable,Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of the unbilled receivable at the beginning of the periodEntergy Corporation 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 periodSubsidiaries Management’s Financial Discussion 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.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Arkansas’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion. Because of the complexity
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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).
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
| | Actuarial Assumption | | Change in Assumption | | Impact on 2015 Qualified Pension Cost | | Impact on 2015 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $4,248 | | $43,590 | | (0.25%) | |
| $3,184 |
| |
| $44,950 |
|
| Rate of return on plan assets | | (0.25%) | | $2,427 | | $— | | (0.25%) | |
| $2,724 |
| | $- |
|
| Rate of increase in compensation | | 0.25% | | $1,525 | | $6,238 | | 0.25% | |
| $1,323 |
| |
| $6,741 |
|
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 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $611 | | $8,062 | | (0.25%) | |
| $541 |
| |
| $7,812 |
|
| Health care cost trend | | 0.25% | | $1,155 | | $6,633 | | 0.25% | |
| $892 |
| |
| $6,143 |
|
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 20152016 was $62.7$37.6 million. Entergy Arkansas anticipates 20162017 qualified pension cost to be $37.6$37 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $13.3 million. Entergy Arkansas contributed $92.4$83 million to its qualified pension plan in 20152016 and estimates 2016-2018 pension contributions will approximate $226.1 million, including $82.8be approximately $79.4 million in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total other postretirement health care and life insurance benefit costincome for Entergy Arkansas in 20152016 was $3.2$5.9 million. Entergy Arkansas expects 20162017 postretirement health care and life insurance benefit income of approximately $5.9$4 million. In 2016, Entergy Arkansas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $2.5 million. Entergy Arkansas contributed $14.7$5.6 million to its other postretirement plans in 20152016 and expects 2016-2018estimates 2017 contributions to approximate $5.3 million, including $4.2 million in 2016.will be approximately $525 thousand.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $106.9 million in the qualified pension benefit obligation and $16 million in the accumulated postretirement
Entergy Arkansas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $15.4 million and other postretirement cost by approximately $2.2 million. Pension funding guidelines, as established byIn 2016, the Employee Retirement Income Security Act of 1974, as amended andmortality projection scale was updated to MP-2016, with no change in the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries newbase mortality assumptions until after 2015, possibly 2016.table assumption.
Entergy Arkansas, Inc. and Subsidiaries
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.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
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 accompanying consolidated balance sheets of Entergy Arkansas, Inc. and Subsidiaries (the “Company”) as of December 31, 20152016 and 2014,2015, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 322321 through 326 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, and audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 20152016 and 2014,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
| |
| $2,086,608 |
| |
| $2,253,564 |
| |
| $2,172,391 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 535,919 |
| | 327,695 |
| | 426,316 |
| | 325,036 |
| | 535,919 |
| | 327,695 |
|
| Purchased power | | 380,081 |
| | 528,815 |
| | 473,326 |
| | 233,350 |
| | 380,081 |
| | 528,815 |
|
| Nuclear refueling outage expenses | | 51,411 |
| | 43,258 |
| | 40,499 |
| | 56,650 |
| | 51,411 |
| | 43,258 |
|
| Other operation and maintenance | | 734,118 |
| | 647,461 |
| | 592,892 |
| | 706,573 |
| | 734,118 |
| | 647,461 |
|
| Decommissioning | | 50,414 |
| | 46,972 |
| | 43,058 |
| | 53,610 |
| | 50,414 |
| | 46,972 |
|
| Taxes other than income taxes | | 99,926 |
| | 91,470 |
| | 89,471 |
| | 93,109 |
| | 99,926 |
| | 91,470 |
|
| Depreciation and amortization | | 246,897 |
| | 236,770 |
| | 230,512 |
| | 264,215 |
| | 246,897 |
| | 236,770 |
|
| Other regulatory credits - net | | (24,608 | ) | | (20,054 | ) | | (10,975 | ) | |
| Other regulatory charges (credits) - net | | | 7,737 |
| | (24,608 | ) | | (20,054 | ) |
| TOTAL | | 2,074,158 |
| | 1,902,387 |
| | 1,885,099 |
| | 1,740,280 |
| | 2,074,158 |
| | 1,902,387 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 179,406 |
| | 270,004 |
| | 305,060 |
| | 346,328 |
| | 179,406 |
| | 270,004 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 14,227 |
| | 7,238 |
| | 10,913 |
| | 17,099 |
| | 14,227 |
| | 7,238 |
|
| Interest and investment income | | 22,382 |
| | 23,075 |
| | 30,148 |
| | 19,087 |
| | 22,382 |
| | 23,075 |
|
| Miscellaneous - net | | (3,385 | ) | | (5,144 | ) | | (4,275 | ) | | (1,446 | ) | | (3,385 | ) | | (5,144 | ) |
| TOTAL | | 33,224 |
| | 25,169 |
| | 36,786 |
| | 34,740 |
| | 33,224 |
| | 25,169 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 105,622 |
| | 93,921 |
| | 91,318 |
| | 115,311 |
| | 105,622 |
| | 93,921 |
|
| Allowance for borrowed funds used during construction | | (7,805 | ) | | (3,769 | ) | | (3,207 | ) | | (9,228 | ) | | (7,805 | ) | | (3,769 | ) |
| TOTAL | | 97,817 |
| | 90,152 |
| | 88,111 |
| | 106,083 |
| | 97,817 |
| | 90,152 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 114,813 |
| | 205,021 |
| | 253,735 |
| | 274,985 |
| | 114,813 |
| | 205,021 |
|
| | | | | | | | | | | | | |
| Income taxes | | 40,541 |
| | 83,629 |
| | 91,787 |
| | 107,773 |
| | 40,541 |
| | 83,629 |
|
| | | | | | | | | | | | | |
| NET INCOME | | 74,272 |
| | 121,392 |
| | 161,948 |
| | 167,212 |
| | 74,272 |
| | 121,392 |
|
| | | | | | | | | | | | | |
| Preferred dividend requirements | | 6,873 |
| | 6,873 |
| | 6,873 |
| | 5,270 |
| | 6,873 |
| | 6,873 |
|
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $67,399 |
| |
| $114,519 |
| |
| $155,075 |
| |
| $161,942 |
| |
| $67,399 |
| |
| $114,519 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
(Page left blank intentionally)
322
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | |
| For the Years Ended December 31, |
| For the Years Ended December 31, |
| |
| 2015 |
| 2014 |
| 2013 |
| 2016 |
| 2015 |
| 2014 |
| |
| (In Thousands) |
| (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
| |
| $167,212 |
| |
| $74,272 |
| |
| $121,392 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 400,156 |
| | 387,945 |
| | 357,639 |
| | 414,933 |
| | 400,156 |
| | 387,945 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (4,330 | ) | | 130,132 |
| | 130,707 |
| | 201,219 |
| | (4,330 | ) | | 130,132 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 20,813 |
| | 25,661 |
| | (26,320 | ) | | (39,118 | ) | | 20,813 |
| | 25,661 |
|
| Fuel inventory | | (11,791 | ) | | (9,394 | ) | | 7,471 |
| | 29,929 |
| | (11,791 | ) | | (9,394 | ) |
| Accounts payable | | (2,528 | ) | | (120,097 | ) | | 141,041 |
| | 143,645 |
| | (2,528 | ) | | (120,097 | ) |
| Prepaid taxes and taxes accrued | | (54,531 | ) | | 14,261 |
| | (204,990 | ) | | 37,485 |
| | (54,531 | ) | | 14,261 |
|
| Interest accrued | | (367 | ) | | (1,786 | ) | | (6,382 | ) | | (3,303 | ) | | (367 | ) | | (1,786 | ) |
| Deferred fuel costs | | 151,332 |
| | (140,483 | ) | | 28,609 |
| | (105,741 | ) | | 151,332 |
| | (140,483 | ) |
| Other working capital accounts | | (44,784 | ) | | 72,411 |
| | (34,909 | ) | | (46,490 | ) | | (44,784 | ) | | 72,411 |
|
| Provisions for estimated losses | | (137 | ) | | (57 | ) | | (76 | ) | | 13,130 |
| | (137 | ) | | (57 | ) |
| Other regulatory assets | | 60,279 |
| | (367,234 | ) | | 214,131 |
| | (95,464 | ) | | 60,279 |
| | (367,234 | ) |
| Pension and other postretirement liabilities | | (110,936 | ) | | 252,639 |
| | (295,435 | ) | | (36,805 | ) | | (110,936 | ) | | 252,639 |
|
| Other assets and liabilities | | (2,558 | ) | | 38,436 |
| | (72,184 | ) | | (4,121 | ) | | (2,558 | ) | | 38,436 |
|
| Net cash flow provided by operating activities | | 474,890 |
| | 403,826 |
| | 401,250 |
| | 676,511 |
| | 474,890 |
| | 403,826 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (624,546 | ) | | (535,464 | ) | | (489,079 | ) | | (666,289 | ) | | (624,546 | ) | | (535,464 | ) |
| Allowance for equity funds used during construction | | 15,882 |
| | 10,789 |
| | 14,550 |
| | 17,754 |
| | 15,882 |
| | 10,789 |
|
| Nuclear fuel purchases | | (132,252 | ) | | (195,092 | ) | | (88,637 | ) | | (102,050 | ) | | (132,252 | ) | | (195,092 | ) |
| Proceeds from sale of nuclear fuel | | 52,281 |
| | 75,860 |
| | 36,478 |
| | 39,313 |
| | 52,281 |
| | 75,860 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 212,954 |
| | 181,489 |
| | 266,391 |
| | 197,390 |
| | 212,954 |
| | 181,489 |
|
| Investment in nuclear decommissioning trust funds | | (223,357 | ) | | (190,062 | ) | | (274,519 | ) | | (213,093 | ) | | (223,357 | ) | | (190,062 | ) |
| Payment for purchase of plant | | | (237,323 | ) | | — |
| | — |
|
| Changes in money pool receivable - net | | 2,218 |
| | 15,313 |
| | (9,496 | ) | | — |
| | 2,218 |
| | 15,313 |
|
| Changes in securitization account | | (108 | ) | | (261 | ) | | 568 |
| | 64 |
| | (108 | ) | | (261 | ) |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | — |
| | — |
| | 10,271 |
| |
Counterparty collateral deposit
| | — |
| | — |
| | 9,000 |
| |
| Insurance proceeds | | 11,654 |
| | 36,600 |
| | — |
| | 10,404 |
| | 11,654 |
| | 36,600 |
|
| Other | | — |
| | 200 |
| | — |
| | 5,835 |
| | — |
| | 200 |
|
| Net cash flow used in investing activities | | (685,274 | ) |
| (600,628 | ) |
| (524,473 | ) | | (947,995 | ) |
| (685,274 | ) |
| (600,628 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | — |
| | 707,465 |
| | 716,595 |
| | 817,563 |
| | — |
| | 707,465 |
|
| Retirement of long-term debt | | (13,234 | ) | | (447,815 | ) | | (442,302 | ) | | (628,433 | ) | | (13,234 | ) | | (447,815 | ) |
| Capital contribution from parent | | | 200,000 |
| | — |
| | — |
|
| Redemption of preferred stock | | | (85,283 | ) | | — |
| | — |
|
| Change in money pool payable - net | | 52,742 |
| | — |
| | — |
| | (1,510 | ) | | 52,742 |
| | — |
|
| Changes in short-term borrowings - net | | (36,278 | ) | | 47,968 |
| | (36,735 | ) | | (11,690 | ) | | (36,278 | ) | | 47,968 |
|
| Dividends paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common stock | | — |
| | (10,000 | ) | | (15,000 | ) | | — |
| | — |
| | (10,000 | ) |
| Preferred stock | | (6,873 | ) | | (6,873 | ) | | (6,873 | ) | | (6,631 | ) | | (6,873 | ) | | (6,873 | ) |
| Other | | 4,657 |
| | (2,460 | ) | | 27 |
| | (1,158 | ) | | 4,657 |
| | (2,460 | ) |
| Net cash flow provided by financing activities | | 1,014 |
| | 288,285 |
| | 215,712 |
| | 282,858 |
| | 1,014 |
| | 288,285 |
|
| Net increase (decrease) in cash and cash equivalents | | (209,370 | ) | | 91,483 |
| | 92,489 |
| | 11,374 |
| | (209,370 | ) | | 91,483 |
|
| Cash and cash equivalents at beginning of period | | 218,505 |
| | 127,022 |
| | 34,533 |
| | 9,135 |
| | 218,505 |
| | 127,022 |
|
| Cash and cash equivalents at end of period | |
| $9,135 |
| |
| $218,505 |
| |
| $127,022 |
| |
| $20,509 |
| |
| $9,135 |
| |
| $218,505 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
| | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $100,435 |
| |
| $90,285 |
| |
| $92,353 |
| |
| $112,912 |
| |
| $100,435 |
| |
| $90,285 |
|
| Income taxes | |
| $103,296 |
| |
| ($48,948 | ) | |
| $184,592 |
| |
| ($135,709 | ) | |
| $103,296 |
| |
| ($48,948 | ) |
| See Notes to Financial Statements. |
| |
|
| |
|
| |
|
| |
|
| |
|
| |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $9,066 |
| |
| $10,526 |
| |
| $20,174 |
| |
| $9,066 |
|
| Temporary cash investments | | 69 |
| | 207,979 |
| | 335 |
| | 69 |
|
| Total cash and cash equivalents | | 9,135 |
| | 218,505 |
| | 20,509 |
| | 9,135 |
|
| Securitization recovery trust account | | 4,204 |
| | 4,096 |
| | 4,140 |
| | 4,204 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 108,636 |
| | 97,314 |
| | 102,229 |
| | 108,636 |
|
| Allowance for doubtful accounts | | (34,226 | ) | | (32,247 | ) | | (1,211 | ) | | (34,226 | ) |
| Associated companies | | 32,987 |
| | 32,187 |
| | 35,286 |
| | 32,987 |
|
| Other | | 84,216 |
| | 110,269 |
| | 58,153 |
| | 84,216 |
|
| Accrued unbilled revenues | | 73,583 |
| | 80,704 |
| | 100,193 |
| | 73,583 |
|
| Total accounts receivable | | 265,196 |
| | 288,227 |
| | 294,650 |
| | 265,196 |
|
| Accumulated deferred income taxes | | — |
| | 21,533 |
| |
| Deferred fuel costs | | — |
| | 143,279 |
| | 96,690 |
| | — |
|
| Fuel inventory - at average cost | | 62,689 |
| | 50,898 |
| | 32,760 |
| | 62,689 |
|
| Materials and supplies - at average cost | | 169,919 |
| | 162,792 |
| | 182,600 |
| | 169,919 |
|
| Deferred nuclear refueling outage costs | | 67,834 |
| | 29,690 |
| | 81,313 |
| | 67,834 |
|
| Prepaid Taxes | | 30,291 |
| | — |
| | — |
| | 30,291 |
|
| Prepayments and other | | 15,145 |
| | 9,588 |
| | 14,293 |
| | 15,145 |
|
| TOTAL | | 624,413 |
| | 928,608 |
| | 726,955 |
| | 624,413 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Decommissioning trust funds | | 771,313 |
| | 769,883 |
| | 834,735 |
| | 771,313 |
|
| Other | | 12,895 |
| | 14,170 |
| | 7,912 |
| | 12,895 |
|
| TOTAL | | 784,208 |
| | 784,053 |
| | 842,647 |
| | 784,208 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 9,536,802 |
| | 9,139,181 |
| | 10,488,060 |
| | 9,536,802 |
|
| Property under capital lease | | 844 |
| | 961 |
| | 716 |
| | 844 |
|
| Construction work in progress | | 388,075 |
| | 284,322 |
| | 304,073 |
| | 388,075 |
|
| Nuclear fuel | | 286,341 |
| | 293,695 |
| | 307,352 |
| | 286,341 |
|
| TOTAL UTILITY PLANT | | 10,212,062 |
| | 9,718,159 |
| | 11,100,201 |
| | 10,212,062 |
|
| Less - accumulated depreciation and amortization | | 4,349,809 |
| | 4,191,959 |
| | 4,635,885 |
| | 4,349,809 |
|
| UTILITY PLANT - NET | | 5,862,253 |
| | 5,526,200 |
| | 6,464,316 |
| | 5,862,253 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 61,438 |
| | 64,214 |
| | 62,646 |
| | 61,438 |
|
| Other regulatory assets (includes securitization property of $54,450 as of December 31, 2015 and $67,877 as of December 31, 2014) | | 1,333,773 |
| | 1,391,276 |
| |
| Other regulatory assets (includes securitization property of $41,164 as of December 31, 2016 and $54,450 as of December 31, 2015) | | | 1,428,029 |
| | 1,333,773 |
|
| Deferred fuel costs | | 66,700 |
| | 65,900 |
| | 66,898 |
| | 66,700 |
|
| Other | | 14,989 |
| | 17,404 |
| | 14,626 |
| | 14,989 |
|
| TOTAL | | 1,476,900 |
| | 1,538,794 |
| | 1,572,199 |
| | 1,476,900 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $9,606,117 |
| |
| $8,747,774 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $55,000 |
| |
| $— |
| |
| $114,700 |
| |
| $55,000 |
|
| Short-term borrowings | | 11,690 |
| | 47,968 |
| | — |
| | 11,690 |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | | 110,464 |
| | 56,078 |
| | 239,711 |
| | 110,464 |
|
| Other | | 177,758 |
| | 174,998 |
| | 185,153 |
| | 177,758 |
|
| Customer deposits | | 118,340 |
| | 115,647 |
| | 97,512 |
| | 118,340 |
|
| Taxes accrued | | — |
| | 24,240 |
| | 7,194 |
| | — |
|
| Accumulated deferred income taxes | | — |
| | 15,009 |
| |
| Interest accrued | | 19,883 |
| | 20,250 |
| | 16,580 |
| | 19,883 |
|
| Deferred fuel costs | | 8,853 |
| | — |
| | — |
| | 8,853 |
|
| Other | | 45,219 |
| | 27,872 |
| | 36,557 |
| | 45,219 |
|
| TOTAL | | 547,207 |
| | 482,062 |
| | 697,407 |
| | 547,207 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,982,812 |
| | 1,997,983 |
| | 2,186,623 |
| | 1,982,812 |
|
| Accumulated deferred investment tax credits | | 36,506 |
| | 37,708 |
| | 35,305 |
| | 36,506 |
|
| Other regulatory liabilities | | 242,913 |
| | 254,036 |
| | 305,907 |
| | 242,913 |
|
| Decommissioning | | 872,346 |
| | 818,351 |
| | 924,353 |
| | 872,346 |
|
| Accumulated provisions | | 5,552 |
| | 5,689 |
| | 18,682 |
| | 5,552 |
|
| Pension and other postretirement liabilities | | 459,153 |
| | 571,870 |
| | 424,234 |
| | 459,153 |
|
| Long-term debt (includes securitization bonds of $61,249 as of December 31, 2015 and $74,161 as of December 31, 2014) | | 2,574,839 |
| | 2,641,073 |
| |
| Long-term debt (includes securitization bonds of $48,139 as of December 31, 2016 and $61,249 as of December 31, 2015) | | | 2,715,085 |
| | 2,574,839 |
|
| Other | | 18,438 |
| | 28,296 |
| | 13,854 |
| | 18,438 |
|
| TOTAL | | 6,192,559 |
| | 6,355,006 |
| | 6,624,043 |
| | 6,192,559 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| Preferred stock without sinking fund | | 116,350 |
| | 116,350 |
| | 31,350 |
| | 116,350 |
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2015 and 2014 | | 470 |
| | 470 |
| |
| Common stock, $0.01 par value, authorized 325,000,000 shares; issued and outstanding 46,980,196 shares in 2016 and 2015 | | | 470 |
| | 470 |
|
| Paid-in capital | | 588,493 |
| | 588,471 |
| | 790,243 |
| | 588,493 |
|
| Retained earnings | | 1,302,695 |
| | 1,235,296 |
| | 1,462,604 |
| | 1,302,695 |
|
| TOTAL | | 1,891,658 |
| | 1,824,237 |
| | 2,253,317 |
| | 1,891,658 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $9,606,117 |
| |
| $8,747,774 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | | | | | | |
| | | Common Equity | | | | Common Equity | | |
| | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total | | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | | (In Thousands) | | | | (In Thousands) | | |
| | | | | | | | | | | | | | | | | |
| Balance at December 31, 2012 | |
| $470 |
| |
| $588,444 |
| |
| $990,702 |
| |
| $1,579,616 |
| |
| Net income | | — |
| | — |
| | 161,948 |
| | 161,948 |
| |
| Common stock dividends | | — |
| | — |
| | (15,000 | ) | | (15,000 | ) | |
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | |
| Other | | — |
| | 27 |
| | — |
| | 27 |
| |
| Balance at December 31, 2013 | |
| $470 |
| |
| $588,471 |
| |
| $1,130,777 |
| |
| $1,719,718 |
| |
| $470 |
| |
| $588,471 |
| |
| $1,130,777 |
| |
| $1,719,718 |
|
| Net income | | — |
| | — |
| | 121,392 |
| | 121,392 |
| | — |
| | — |
| | 121,392 |
| | 121,392 |
|
| Common stock dividends | | — |
| | — |
| | (10,000 | ) | | (10,000 | ) | | — |
| | — |
| | (10,000 | ) | | (10,000 | ) |
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) |
| Balance at December 31, 2014 | |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
| |
| $470 |
| |
| $588,471 |
| |
| $1,235,296 |
| |
| $1,824,237 |
|
| Net income | | — |
| | — |
| | 74,272 |
| | 74,272 |
| | — |
| | — |
| | 74,272 |
| | 74,272 |
|
| Preferred stock dividends | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) | | — |
| | — |
| | (6,873 | ) | | (6,873 | ) |
| Other | | — |
| | 22 |
| | — |
| | 22 |
| | — |
| | 22 |
| | — |
| | 22 |
|
| Balance at December 31, 2015 | |
| $470 |
| |
| $588,493 |
| |
| $1,302,695 |
| |
| $1,891,658 |
| |
| $470 |
| |
| $588,493 |
| |
| $1,302,695 |
| |
| $1,891,658 |
|
| Net income | | | — |
| | — |
| | 167,212 |
| | 167,212 |
|
| Capital contributions from parent | | | — |
| | 200,000 |
| | — |
| | 200,000 |
|
| Capital stock redemption | | | — |
| | 1,750 |
| | (2,033 | ) | | (283 | ) |
| Preferred stock dividends | | | — |
| | — |
| | (5,270 | ) | | (5,270 | ) |
| Balance at December 31, 2016 | | |
| $470 |
| |
| $790,243 |
| |
| $1,462,604 |
| |
| $2,253,317 |
|
| | | | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY ARKANSAS, INC. AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | | | |
| | | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | | | | | | | | | |
| Operating revenues | |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
| |
| $2,127,004 |
| |
| $2,084,310 |
| |
| $2,086,608 |
| |
| $2,253,564 |
| |
| $2,172,391 |
| |
| $2,190,159 |
| |
| $2,127,004 |
|
| Net Income | |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
| |
| $152,365 |
| |
| $164,891 |
| |
| Net income | | |
| $167,212 |
| |
| $74,272 |
| |
| $121,392 |
| |
| $161,948 |
| |
| $152,365 |
|
| Total assets | |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $8,007,707 |
| |
| $7,797,123 |
| |
| $7,195,247 |
| |
| $9,606,117 |
| |
| $8,747,774 |
| |
| $8,777,655 |
| |
| $8,007,707 |
| |
| $7,797,123 |
|
| Long-term obligations (a) | |
| $2,691,189 |
| |
| $2,757,423 |
| |
| $2,424,969 |
| |
| $1,887,923 |
| |
| $1,975,306 |
| |
| $2,746,435 |
| |
| $2,691,189 |
| |
| $2,757,423 |
| |
| $2,424,969 |
| |
| $1,887,923 |
|
| | | | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt) and preferred stock without sinking fund. | | | | | | | | | | | | | | | | | | | | | | |
| | | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | | (Dollars In Millions) | | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Residential | |
| $824 |
| |
| $755 |
| |
| $772 |
| |
| $766 |
| |
| $756 |
| |
| $789 |
| |
| $824 |
| |
| $755 |
| |
| $772 |
| |
| $766 |
|
| Commercial | | 515 |
| | 461 |
| | 469 |
| | 472 |
| | 450 |
| | 495 |
| | 515 |
| | 461 |
| | 469 |
| | 472 |
|
| Industrial | | 477 |
| | 424 |
| | 433 |
| | 439 |
| | 421 |
| | 446 |
| | 477 |
| | 424 |
| | 433 |
| | 439 |
|
| Governmental | | 20 |
| | 18 |
| | 19 |
| | 20 |
| | 20 |
| | 18 |
| | 20 |
| | 18 |
| | 19 |
| | 20 |
|
| Total retail | | 1,836 |
| | 1,658 |
| | 1,693 |
| | 1,697 |
| | 1,647 |
| | 1,748 |
| | 1,836 |
| | 1,658 |
| | 1,693 |
| | 1,697 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Sales for resale: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 128 |
| | 131 |
| | 346 |
| | 320 |
| | 279 |
| | 49 |
| | 128 |
| | 131 |
| | 346 |
| | 320 |
|
| Non-associated companies | | 195 |
| | 282 |
| | 83 |
| | 49 |
| | 96 |
| | 118 |
| | 195 |
| | 282 |
| | 83 |
| | 49 |
|
| Other | | 95 |
| | 101 |
| | 68 |
| | 61 |
| | 62 |
| | 172 |
| | 95 |
| | 101 |
| | 68 |
| | 61 |
|
| Total | |
| $2,254 |
| |
| $2,172 |
| |
| $2,190 |
| |
| $2,127 |
| |
| $2,084 |
| |
| $2,087 |
| |
| $2,254 |
| |
| $2,172 |
| |
| $2,190 |
| |
| $2,127 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | | |
| | |
| | |
| | |
| | | | |
| | |
| | |
| | |
|
| Residential | | 8,016 |
| | 8,070 |
| | 7,921 |
| | 7,859 |
| | 8,229 |
| | 7,618 |
| | 8,016 |
| | 8,070 |
| | 7,921 |
| | 7,859 |
|
| Commercial | | 6,020 |
| | 5,934 |
| | 5,929 |
| | 6,046 |
| | 6,051 |
| | 5,988 |
| | 6,020 |
| | 5,934 |
| | 5,929 |
| | 6,046 |
|
| Industrial | | 6,889 |
| | 6,808 |
| | 6,769 |
| | 6,925 |
| | 7,029 |
| | 6,795 |
| | 6,889 |
| | 6,808 |
| | 6,769 |
| | 6,925 |
|
| Governmental | | 235 |
| | 238 |
| | 241 |
| | 257 |
| | 275 |
| | 237 |
| | 235 |
| | 238 |
| | 241 |
| | 257 |
|
| Total retail | | 21,160 |
| | 21,050 |
| | 20,860 |
| | 21,087 |
| | 21,584 |
| | 20,638 |
| | 21,160 |
| | 21,050 |
| | 20,860 |
| | 21,087 |
|
| | | | | | | | | | | | | | | | | | | | | |
| Sales for resale: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
| Associated companies | | 2,239 |
| | 2,299 |
| | 7,918 |
| | 7,926 |
| | 6,893 |
| | 1,609 |
| | 2,239 |
| | 2,299 |
| | 7,918 |
| | 7,926 |
|
| Non-associated companies | | 7,980 |
| | 8,003 |
| | 1,011 |
| | 1,093 |
| | 1,304 |
| | 7,115 |
| | 7,980 |
| | 8,003 |
| | 1,011 |
| | 1,093 |
|
| Total | | 31,379 |
| | 31,352 |
| | 29,789 |
| | 30,106 |
| | 29,781 |
| | 29,362 |
| | 31,379 |
| | 31,352 |
| | 29,789 |
| | 30,106 |
|
ENTERGY LOUISIANA, LLC AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Entergy Louisiana and Entergy Gulf States Louisiana Business Combination
Entergy Louisiana and Entergy Gulf States Louisiana filed an application with the LPSC in September 2014 seeking authorization to undertake the transactions that would result in the combination of Entergy Louisiana and Entergy Gulf States Louisiana into a single public utility. In the application, Entergy Louisiana and Entergy Gulf States Louisiana identified potential benefits, including enhanced economic and customer diversity, enhanced geographic and supply diversity, and greater administrative efficiency. In the initial proceedings with the LPSC, Entergy Louisiana and Entergy Gulf States Louisiana estimated that the business combination could produce up to $128 million in measurable customer benefits during the first ten years following the transaction’s close including proposed guaranteed customer credits of $97 million in the first nine years. In April 2015 the LPSC staff and intervenors filed testimony in the LPSC business combination proceeding. The testimony recommended an extensive set of conditions that would be required in order to recommend that the LPSC find that the business combination was in the public interest. The LPSC staff’s primary concern appeared to be potential shifting in fuel costs between Entergy Louisiana and Entergy Gulf States Louisiana customers. In May 2015, Entergy Louisiana and Entergy Gulf States Louisiana filed rebuttal testimony. After the testimony was filed with the LPSC, the parties engaged in settlement discussions that ultimately led to the execution of an uncontested stipulated settlement (“stipulated settlement”), which was filed with the LPSC in July 2015. Through the stipulated settlement, the parties agreed to terms upon which to recommend that the LPSC find that the business combination was in the public interest. The stipulated settlement, which was either joined, or unopposed, by all parties to the LPSC proceeding, represents a compromise of stakeholder positions and was the result of an extensive period of analysis, discovery, and negotiation. The stipulated settlement provides $107 million in guaranteed customer benefits during the first nine years following the transaction’s close. Additionally, the combined company will honor the 2013 Entergy Louisiana and Entergy Gulf States Louisiana rate case settlements, including the commitments that (1) there will be no rate increase for legacy Entergy Gulf States Louisiana customers for the 2014 test year, and (2) through the 2016 test year formula rate plan, Entergy Louisiana (as a combined entity) will not raise rates by more than $30 million, net of the $10 million rate increase included in the Entergy Louisiana legacy formula rate plan. The stipulated settlement also describes the process for implementing a fuel-tracking mechanism that is designed to address potential effects arising from the shifting of fuel costs between legacy Entergy Louisiana and legacy Entergy Gulf States Louisiana customers as a result of the combination of those companies’ fuel adjustment clauses. Specifically, the fuel tracker would reallocate such cost shifts as between legacy customers of the companies on an after-the-fact basis, and the calculation of the fuel tracker will be submitted annually in a compliance filing. The stipulated settlement also provides that Entergy Gulf States Louisiana and Entergy Louisiana are permitted to defer certain external costs that were incurred to achieve the business combination’s customer benefits. The deferred amount, which shall not exceed $25 million, will be subject to a prudence review and amortized over a 10-year period. In 2015 deferrals of $16 million for these external costs was recorded. A hearing on the stipulated settlement in the LPSC proceeding was held in July 2015. In August 2015 the LPSC approved the business combination.
In April 2015 the FERC approved applications requesting authorization for the business combination. In August 2015 the NRC approved the applications for the River Bend and Waterford 3 license transfers as part of the steps to complete the business combination.
On October 1, 2015, the businesses formerly conducted by Entergy Louisiana and Entergy Gulf States Louisiana were combined into a single public utility. With the completion of the business combination, Entergy Louisiana holds substantially all of the assets, and has assumed the liabilities, of Entergy Louisiana and Entergy Gulf States Louisiana. The combination was accounted for as a transaction between entities under common control. The effect of the business combination has been retrospectively applied to Entergy Louisiana's financial statements that are presented in this report. See Note 2 to the financial statements for further discussion of the business combination and related customer credits.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Results of Operations
Net Income
2016 Compared to 2015
Net income increased $175.4 million primarily due to the effect of a settlement with the IRS related to the 2010-2011 IRS audit, which resulted in a $136.1 million reduction of income tax expense. Also contributing to the increase were lower other operation and maintenance expenses, higher net revenue, and higher other income. The increase was partially offset by higher depreciation and amortization expenses, higher interest expense, and higher nuclear refueling outage expenses.
2015 Compared to 2014
Net income increased slightly, by $0.6 million, primarily due to higher net revenue and a lower effective income tax rate, offset by higher other operation and maintenance expenses, higher depreciation and amortization expenses, lower other income, and higher interest expense.
2014Net Revenue
2016 Compared to 20132015
Net income increased $31.9 millionrevenue 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 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $2,408.8 |
|
| Retail electric price | 69.0 |
|
| Transmission equalization | (6.5 | ) |
| Volume/weather | (6.7 | ) |
| Louisiana Act 55 financing savings obligation | (17.2 | ) |
| Other | (9.0 | ) |
| 2016 net revenue |
| $2,438.4 |
|
The retail electric price variance is primarily due to higher netan increase in formula rate plan revenues, implemented with the first billing cycle of March 2016, to collect the estimated first-year revenue requirement related to the purchase of Power Blocks 3 and higher other income,4 of the Union Power Station. See Note 2 to the financial statements for further discussion.
The transmission equalization variance is primarily due to changes in transmission investments, including Entergy Louisiana’s exit from the System Agreement in August 2016.
The volume/weather variance is primarily due to the effect of less favorable weather on residential sales, partially offset by higher other operationan increase in industrial usage and maintenance expenses, a higher effective income tax rate, higher depreciation and amortization expenses, and higher interest expense.an increase in volume during the unbilled period. The increase
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
in industrial usage is primarily due to increased demand from new customers and expansion projects, primarily in the chemicals industry.
The Louisiana Act 55 financing savings obligation variance results from a regulatory charge for tax savings to be shared with customers per an agreement approved by the LPSC. The tax savings resulted from the 2010-2011 IRS audit settlement on the treatment of the Louisiana Act 55 financing of storm costs for Hurricane Gustav and Hurricane Ike. See Note 3 to the financial statements for additional discussion of the settlement and benefit sharing.
Included in Other is a provision of $23 million recorded in 2016 related to the settlement of the Waterford 3 replacement steam generator prudence review proceeding, offset by a provision of $32 million recorded in 2015 related to the uncertainty at that time associated with the resolution of the Waterford 3 replacement steam generator prudence review proceeding. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
| 2014 net revenue |
| $2,246.1 |
|
| Retail electric price | 180.0 |
|
| Volume/weather | 39.5 |
|
| Waterford 3 replacement steam generator provision | (32.0 | ) |
| MISO deferral | (32.0 | ) |
| Other | 7.2 |
|
| 2015 net revenue |
| $2,408.8 |
|
The retail electric price variance is primarily due to formula rate plan increases, as approved by the LPSC, effective December 2014 and January 2015. Entergy Louisiana’s formula rate plan increases are discussed in Note 2 to the financial statements.
The volume/weather variance is primarily due to an increase of 841 GWh, or 2%, in billed electricity usage, as a result of increased industrial usage primarily due to increased demand for existing large refinery customers, new customers, and expansion projects primarily in the chemicals industry, partially offset by a decrease in demand in the chemicals industry as a result of a seasonal outage for an existing customer.
The Waterford 3 replacement steam generator provision is due to a regulatory charge of approximately $32 million recorded in 2015 related to the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project. See Note 2 to the financial statements for a discussion of the Waterford 3 replacement steam generator prudence review proceeding.
The MISO deferral variance is due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in other operation and maintenance
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
expenses. See Note 2 to the financial statements for further discussion of the recovery of non-fuel MISO-related charges.
2014
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Variances
2016 Compared to 20132015
Net revenue consists of operating revenues net of: 1) fuel, fuel-relatedNuclear refueling outage 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 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $2,122.2 |
|
Volume/weather | 31.8 |
|
Asset retirement obligation | 29.5 |
|
MISO deferral | 25.3 |
|
Retail electric price | 16.8 |
|
Other | 20.5 |
|
2014 net revenue |
| $2,246.1 |
|
The volume/weather variance isincreased primarily due to an increasethe amortization of 1,842 GWh, or 4%, in billed electricity usage primarily due to higher industrial usage, primarily inexpenses associated with the chemicals industry, and the effect of more favorable weather primarily on residential sales.refueling outages at Waterford 3.
The asset retirement obligation affects net revenue because Entergy Louisiana records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The variance is primarily caused by an increase in regulatory credits because of a decrease in decommissioning trust earnings and an increase in regulatory credits to realign the asset retirement obligation regulatory asset with regulatory treatment.
The MISO deferral variance is due to the deferral in 2014 of non-fuel MISO-related charges, as approved by the LPSC. The deferral of non-fuel MISO-related charges is partially offset in otherOther operation and maintenance expenses.expenses decreased primarily due to:
the $45 million write-off recorded in 2015 to recognize the portion of the assets associated with the Waterford 3 replacement steam generator project no longer probable of recovery. See Note 2 to the financial statements for further discussion of the recoveryprudence review proceeding; and
a decrease of non-fuel MISO-related charges.$35 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement costs as a result of higher discount rates used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The retail electric price variance isdecrease was partially offset by an increase of $19.9 million in nuclear generation expenses primarily due to higher nuclear labor costs, including contract labor.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including Power Blocks 3 and 4 of the Union Power Station purchased in March 2016.
Other income increased primarily due to an increase in affiliated purchased power capacity costs that are recovered through basethe allowance for equity funds used during construction due to higher construction work in progress in 2016, which included the St. Charles Power Station project and increased distribution and transmission spending. The increase was also due to higher trust income in 2016 on the River Bend and Waterford 3 decommissioning trust fund investments.
Interest expense increased primarily due to:
the issuance in March 2016 of $425 million of 3.25% Series collateral trust mortgage bonds;
the issuance in March 2016 of $200 million of 4.95% Series first mortgage bonds; and
the issuance in October 2016 of $400 million of 2.40% Series collateral trust mortgage bonds.
The increase was partially offset by the refinancing at lower interest rates set in the annual formula rate plan mechanism and a formula rate plan increase effective December 2014. Entergy Louisiana’s formula rate plan is discussed inof certain first mortgage bonds. See Note 25 to the financial statements.
Other Income Statement Variancesstatements for details of long-term debt.
2015 Compared to 2014
Nuclear refueling outage expenses decreased primarily due to the amortization of lower expenses associated with the refueling outage at Waterford 3.
Other operation and maintenance expenses increased primarily due to:
the $45 million write-off recorded in 2015 to recognize that a portion of the assets associated with the Waterford 3 replacement steam generator project is no longer probable of recovery and the $16 million write-off recorded in 2014 due to the uncertainty at the time associated with the resolution of the Waterford 3 replacement steam
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
generator project prudence review. See Note 2 to the financial statements for further discussion of the prudence review proceeding;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
an increase of $19.9 million in nuclear generation expenses primarily due to an increased scope of work performed in 2015;
an increase of $14.6 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefitsbenefit costs;
an increase of $11 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO. There is no effect on net income due to the recovery of these costs through the MISO cost recovery mechanism. See Note 2 to the financial statements for further information on the recovery of these costs;
an increase of $9.4 million due to the amortization effective December 2014 of costs related to the transition and implementation of joining the MISO RTO; and
an increase resulting from losses of $1.7 million on the sale of surplus diesel inventory in 2015 compared to gains of $5.1 million on the sale of surplus oil inventory and $2.2 million on the sale of surplus diesel inventory in 2014.
The increase was partially offset by a decrease of $10.4 million related to the Entergy Louisiana and Entergy Gulf States Louisiana business combination, including the deferral recorded in 2015, as approved by the LPSC, of $15.8 million of certain external costs incurred. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” aboveNote 2 to the financial statements for a discussion of the recovery of the business combination.combination costs.
Taxes other than income taxes increased primarily due to an increase in payroll taxes and ad valorem taxes, partially offset by lower local franchise taxes. Ad valorem taxes increased primarily due to higher assessments and higher millage rates. Local franchise taxes decreased primarily due to lower residential and commercial revenues as compared to prior year.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the Ninemile Unit 6 project, which was placed in service in December 2014.
Other income decreased primarily due to a decrease in the allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, which included the Ninemile Unit 6 project and $7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC. The decrease was partially offset by an increase of $9.7 million due to income earned on preferred membership interests purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements for a discussion of the Act 55 storm cost financing.
Interest expense increased primarily due to:
the decrease in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project, which was placed in service in December 2014;
the issuance of $250 million of 4.95% Series first mortgage bonds in November 2014; and
the issuance of two series totaling $300 million of 3.78% Series first mortgage bonds in July 2014.
The increase was partially offset by the retirement, at maturity, of $250 million of 1.875% Series first mortgage bonds in December 2014.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014, were 12.6%, 28.6%, and 29.3%, respectively. The difference in the effective income tax rate of 12.6% for 2016 versus the statutory rate of 35% for 2016 was primarily
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
2014 Compared to 2013
Other operation and maintenance expenses increased primarily due to:
an increase of $17.4 million due to administration fees related to the participation in the MISO RTO effective December 2013. The LPSC approved deferralreversal of these expenses resulting in no net income effect;
a $16 million write-off recorded in 2014 becauseportion of the uncertainty associated with the resolution of the Waterford 3 replacement steam generator project prudence review. See Note 2 to the financial statementsprovision for further discussion of the prudence review;
an increase of $15 million in regulatory, consulting, and legal fees;
an increase of $9.1 million in nuclear generation expenses primarily due to higher labor costs, including contract labor, higher materials costs, and higher NRC fees;
an increase of $8.8 million in fossil-fueled generation expenses primarily due to an overall higher scope of work done during plant outages as compared to prior year;
an increase of $3.8 millionuncertain tax positions as a result of higher write-offsthe settlement of uncollectible accounts in 2014; and
several individually insignificant items.
The increase was partially offset by:
a decrease of $44.7 million in compensation and benefits costs primarily due to an increasethe 2010-2011 IRS audit in the discount rates used to determine net periodic pensionsecond quarter 2016 and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees,book and a settlement charge recognized in September 2013tax differences related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs; and
a decrease of $13.1 million due to costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Othernon-taxable income increased primarily due to:
an increase of $12.3 million due to distributions earned on preferred membership interests, purchased from Entergy Holdings Company with the proceeds received in August 2014 from the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
$7.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac as approved by the LPSC; and
the increase in allowance for equity funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project.
The increase was partially offset by higher realized gains in 2013 on River Bend and Waterford 3 decommissioning trust fund investments. There is no effect on netstate income as these investment gains are offset by a corresponding amount of regulatory charges.
Interest expense increased primarily due to:
the issuance of $325 million of 4.05% Series first mortgage bonds in August 2013;
the issuance of $170 million of 5.0% Series first mortgage bonds in June 2014;
the issuance of two series totaling $300 million of 3.78% Series first mortgage bonds in July 2014; and
$3.6 million of carrying charges recorded in 2014 on storm restoration costs related to Hurricane Isaac, as approved by the LPSC.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by an increase in the allowance for borrowed funds used during construction due to a higher construction work in progress balance in 2014, including the Ninemile Unit 6 project.
Income Taxes
The effective income tax rates for 2015, 2014, and 2013, were 28.6%, 29.3%, and 25.1%, respectively.taxes. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Louisiana Tax Legislation
In 2016 the Louisiana Legislature conducted special sessions which resulted in various corporate tax changes. A summary of the changes follows:
Restrictions were imposed on the utilization of Louisiana net operating loss carryovers. Entergy Louisiana has determined that no additional valuation allowance is necessary at this time on its Louisiana net operating loss carryovers.
Effective January 1, 2017, limited liability companies that elect to be taxed as corporations for federal income tax purposes and that conduct business in Louisiana will be subject to Louisiana franchise tax. Entergy currently estimates that its combined Louisiana franchise tax liability may increase in the range of $4 million to $10 million as a result of this change.
The Louisiana state sales tax rate was increased by 1% and certain tax exemptions were made temporarily inoperable. The combination of these two changes will likely increase Entergy Louisiana’s costs related to fuel, capital expenditures, and other operating expenses. These temporary provisions are currently scheduled to be in place through mid-2018.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, 2014, and 20132014 were as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $320,516 |
| |
| $139,588 |
| |
| $65,772 |
|
| $35,102 |
| |
| $320,516 |
| |
| $139,588 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
| | | |
| | |
|
| Operating activities | 1,155,516 |
| | 1,718,591 |
| | 1,097,498 |
| 1,037,912 |
| | 1,155,516 |
| | 1,718,591 |
|
| Investing activities | (994,208 | ) | | (1,330,041 | ) | | (877,451 | ) | (1,474,065 | ) | | (994,208 | ) | | (1,330,041 | ) |
| Financing activities | (446,722 | ) | | (207,622 | ) | | (146,231 | ) | 614,901 |
| | (446,722 | ) | | (207,622 | ) |
| Net increase (decrease) in cash and cash equivalents | (285,414 | ) | | 180,928 |
| | 73,816 |
| 178,748 |
| | (285,414 | ) | | 180,928 |
|
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $35,102 |
| |
| $320,516 |
| |
| $139,588 |
|
| $213,850 |
| |
| $35,102 |
| |
| $320,516 |
|
Operating Activities
Net cash flow provided by operating activities decreased $117.6 million in 2016 primarily due to:
an increase of $67.5 million in income tax payments in 2016. Entergy Louisiana had income tax payments of $156.6 million in 2016 and $89.1 million in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax payments resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit, 2016 payments for state taxes resulting from the correlative effect of the final settlement of the 2006-2007 IRS audit, and the effect of net operating loss limitations discussed above in “Louisiana Tax Legislation.” The 2015 income tax payments
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
resulted primarily from adjustments associated with the settlement of the 2008-2009 IRS Audit. See Note 3 to the financial statements for a discussion of the income tax audits;
an increase of $80.7 million in interest paid resulting from an increase in interest expense, including a payment of $60 million made in March 2016 related to the purchase of a beneficial interest in the Waterford 3 leased assets. See Note 10 to the financial statements for a discussion of the purchase of a beneficial interest in the Waterford 3 leased assets;
the timing of collections from customers and payments to vendors; and
a decrease due to the timing of recovery of fuel and purchased power costs in 2016.
The decrease was partially offset by proceeds of $37.8 million received in 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed and a decrease of $30.5 million in spending on nuclear refueling outages in 2016. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Net cash flow provided by operating activities decreased $563.1 million in 2015 primarily due to:
proceeds of $309.5 million received in 2014 from the Louisiana Utilities Restoration Corporation as a result of the Louisiana Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
income tax payments of $89.1 million in 2015 and income tax refunds of $242.4 million in 2014. Entergy Louisiana had income tax payments in 2015 and income tax refunds in 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2015 income tax payments arewere primarily due to adjustments associated with the settlement of the IRS Audit of the 2008-2009 tax years whereas the 2014 income tax refunds arewere primarily due to favorable adjustments allowed in the IRS Audit of the 2006-2007 tax years and a carryback of a 2008 net operating loss. See Note 3 to the financial statements for a discussion of the income tax audits; and
an increase of $17.1 million in spending on nuclear refueling outages in 2015.
The decrease was partially offset by increased net revenue, as discussed above.
Investing Activities
Net cash flow provided by operatingused in investing activities increased $621.1$479.9 million in 20142016 primarily due to:
proceedsthe purchase of $309.5 million received in 2014 from the Louisiana Utilities Restoration Corporation as a resultPower Blocks 3 and 4 of the Louisiana Act 55 storm cost financing.Union Power Station for an aggregate purchase price of approximately $475 million in March 2016. See Note 214 to the financial statements andfor discussion of the Union Power Station purchase;
an increase of $130.7 million in fossil-fueled generation construction expenditures primarily due to spending on the St. Charles Power Station project in 2016;
cash proceeds of $59.6 million received in 2015 from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “Hurricane IsaacState and Local Rate Regulation and Fuel-Cost Recovery- Retail Rates - Electric - Filings with the City Council” below for afurther discussion of the Act 55 storm cost financing;transfer;
an increase of $52 million in transmission construction expenditures due to a higher scope of work performed in 2016 as compared to the same period in 2015; and
an increase of $20.5 million due to various information technology projects and upgrades in 2016.
The increase was partially offset by:
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 service deliveries, and the timing of cash payments during the nuclear fuel cycle;
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
an increaseproceeds of $57.9 million received in income tax refunds of $213.9 million. Entergy Louisiana had income tax refunds in 2014 in accordance with2016 from the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds are primarily dueDOE resulting from litigation regarding spent nuclear fuel storage costs that were previously capitalized. See Note 8 to favorable adjustments allowed in the IRS Auditfinancial statements for discussion of the 2006-2007 tax years and a carryback of a 2008 net operating loss;
the timing of collections from customers;spent nuclear fuel litigation; and
a decrease of $13.7$16.9 million in nuclear construction expenditures primarily due to decreased spending on nuclear refueling outages in 2014 compared to 2013.
The increase was partially offset by an increase of $52 million in pension contributions in 2014 and an increase of $20.3 million in interest paid resulting from an increase in interest expense, as discussed above. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Investing Activitiescompliance with NRC post-Fukushima requirements.
Net cash flow used in investing activities decreased $335.8 million in 2015 primarily due to:
the investment in 2014 of $293.5 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
the deposit of $268.6 million into the storm reserve escrow account in 2014;
cash proceeds of $59.6 million from the transfer of Algiers assets to Entergy New Orleans in September 2015. See “State and Local Rate Regulation and Fuel-Cost Recovery - Retail Rates - Electric - Filings with the City Council” below for further discussion of the transfer; and
a decrease in fossil-fueled generation construction expenditures primarily due to decreased spending on the Ninemile Unit 6 project, which was placed in service in December 2014.
The decrease was partially offset by the following:
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;
an increase in nuclear expenditures primarily due to compliance with NRC post-Fukushima requirements and a higher scope of work on various nuclear projects in 2015;
an increase in distribution construction expenditures due to an increased scope of work performed in 2015;
an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and
money pool activity.
Increases in Entergy Louisiana'sLouisiana’s receivable from the money pool isare a use of cash flow, and Entergy Louisiana'sLouisiana’s receivable from the money pool increased by $3.3 million in 2015 compared to decreasing by $16.8 million in 2014. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries'subsidiaries’ need for external short-term borrowings.
NetFinancing Activities
Entergy Louisiana’s financing activities provided $614.9 million of cash flow used in investing activities increased $452.62016 compared to using $446.7 million in 20142015 primarily due to:to the following activity:
the net issuance of $961.2 million of long-term debt in 2016 compared to the net retirement of $103.4 million of long-term debt in 2015;
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination;
net repayments of borrowings of $56.6 million on the nuclear fuel company variable interest entity’s credit facility in 2016 compared to net borrowings of $14.3 million in 2015; and
an increase of $59.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Blocks 3 and 4 of the Union Power Station.
the investment in 2014 of $293.5 million in affiliate securities as a result of the Act 55 storm cost financing. See Note 2 to the financial statements and “Hurricane Isaac” below for a discussion of the Act 55 storm cost financing;
the deposit of $268.6 million into the storm reserve escrow account in 2014; and
the withdrawal of $252.5 million from the storm reserve escrow account in 2013.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
The increase was partially offset by:
a decrease in fossil-fueled generation construction expenditures due to lower spending on the Ninemile Unit 6 project;
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; and
money pool activity.
Decreases in Entergy Louisiana’s receivable from the money pool are a source of cash flow, and Entergy Louisiana’s receivable from the money pool decreased by $16.8 million in 2014 compared to increasing by $10.1 million in 2013.
Financing Activities
Net cash flow used by financing activities increased $239.1 million in 2015 primarily due to:
the retirement of $104 million onof long-term debt in 2015 compared to the net issuance of $239.4 million of long-term debt in 2014; and
the redemption in September 2015 of $100 million of 6.95% Series and $10 million of 8.25% Series preferred membership interests in connection with the Entergy Louisiana and Entergy Gulf States Louisiana business combination, which is discussed above.combination.
The increase was partially offset by a decrease of $261.5 million in common equity distributions.
Net cash flow used by financing activities increased $61.4 milliondistributions in 2014 primarily due toanticipation of the net issuancepurchase of $239.4 millionPower Blocks 3 and 4 of long-term debt in 2014 compared to the net issuance of $381.7 million of long-term debt in 2013, partially offset by borrowings of $28.3 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to the repayment of borrowings of $36.9 million in 2013.Union Power Station.
See Note 5 to the financial statements for details of long-term debt.
Capital Structure
Entergy Louisiana’s capitalization is balanced between equity and debt, as shown in the following table. The decreaseincrease in the debt to capital ratio for Entergy Louisiana is primarily due to the increaseissuance of long-term debt in members’ equity.
2016.
| | | | December 31,
2015 | | December 31,
2014 | December 31,
2016 | | December 31,
2015 |
| Debt to capital | 50.8 | % | | 53.4 | % | 53.4 | % | | 50.8 | % |
| Effect of excluding securitization bonds | (0.6 | %) | | (0.7 | %) | (0.5 | %) | | (0.6 | %) |
| Debt to capital, excluding securitization bonds (a) | 50.2 | % | | 52.7 | % | 52.9 | % | | 50.2 | % |
| Effect of subtracting cash | (0.2 | %) | | (1.7 | %) | (0.9 | %) | | (0.2 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 50.0 | % | | 51.0 | % | 52.0 | % | | 50.0 | % |
| |
| (a) | Calculation excludes the securitization bonds, which are non-recourse to Entergy Louisiana. |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Louisiana uses the debt to capital ratios
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition.condition because the securitization bonds are non-recourse to Entergy Louisiana, as more fully described in Note 5 to the financial statements. Entergy Louisiana also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Louisiana’s financial condition because net debt indicates Entergy Louisiana’s outstanding debt position that could not be readily satisfied by cash and cash equivalents.equivalents on hand.
Entergy Louisiana seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Louisiana may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Louisiana may receive equity contributions to maintain the targeted capital structure.
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
Uses of Capital
Entergy 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.
Following are the amounts of Entergy Louisiana’s planned construction and other capital investments.
| | | | 2016 | | 2017 | | 2018 | 2017 | | 2018 | | 2019 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $955 |
| |
| $810 |
| |
| $800 |
|
| $875 |
| |
| $820 |
| |
| $590 |
|
| Transmission | 270 |
| | 375 |
| | 285 |
| 410 |
| | 400 |
| | 375 |
|
| Distribution | 290 |
| | 310 |
| | 275 |
| 260 |
| | 300 |
| | 275 |
|
| Other | 60 |
| | 50 |
| | 45 |
| 175 |
| | 115 |
| | 70 |
|
| Total |
| $1,575 |
| |
| $1,545 |
| |
| $1,405 |
|
| $1,720 |
| |
| $1,635 |
| |
| $1,310 |
|
Following are the amounts of Entergy Louisiana’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total | 2017 | | 2018-2019 | | 2020-2021 | | After 2021 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $271 |
| |
| $1,329 |
| |
| $718 |
| |
| $5,655 |
| |
| $7,973 |
|
| $475 |
| |
| $1,151 |
| |
| $980 |
| |
| $6,649 |
| |
| $9,255 |
|
| Operating leases |
| $17 |
| |
| $26 |
| |
| $20 |
| |
| $7 |
| |
| $70 |
|
| $24 |
| |
| $44 |
| |
| $29 |
| |
| $23 |
| |
| $120 |
|
| Purchase obligations (b) |
| $793 |
| |
| $1,387 |
| |
| $1,177 |
| |
| $3,361 |
| |
| $6,718 |
|
| $652 |
| |
| $1,094 |
| |
| $957 |
| |
| $5,215 |
| |
| $7,918 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | 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. |
In addition to the contractual obligations given above, Entergy Louisiana currently expects to contribute approximately $83.9$87.7 million to its qualified pension plans and approximately $18.9$19.3 million to its other postretirement health care and life insurance plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017. 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 Louisiana has $796.9$657.2 million of unrecognized tax benefits and interest net of unused tax attributes for which the timing of payments beyond 12 months cannot be
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
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.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Louisiana includes specific investments, such as the UnionSt. Charles Power Station acquisitionand Lake Charles Power Station,
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
each discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintainenhance reliability and improve service to customers, including initial investment to support smart meter deployment;advanced metering; resource planning, including potential generation projects; system improvements; investments in the nuclear fleet, as discussed below in “Nuclear Matters;” and other investments. 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 and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital.
As an indirect, majority-owned subsidiary of Entergy Corporation, Entergy Louisiana pays distributions from its earnings at a percentage determined monthly. Entergy Louisiana’s long-term debt indenture contains restrictions on the payment of cash dividends or other distributions on its common and preferred membership interests.
St. Charles Power Station
In August 2015, Entergy Louisiana filed with the LPSC an application seeking certification that the public necessity and convenience would be served by the construction of the St. Charles Power Station, a nominal 980 megawatt combined-cycle generating unit, on land adjacent to the existing Little Gypsy plant in St. Charles Parish, Louisiana. Discovery has begun in the proceeding.It is currently estimated to cost $869 million to construct, including transmission interconnection and other related costs. Testimony has beenwas filed by LPSC staff and intervenors, with LPSC staff concluding that the construction of the project serves the public convenience and necessity. Three intervenors contendcontended that Entergy Louisiana hashad not established that construction of the project is in the public interest, claiming that the RFPrequest for proposal excluded consideration of certain resources that could be more cost effective, that the RFPrequest for proposal provided undue preference to the self-build option, and that a 30-year capacity commitment iswas not warranted by current supply conditions. The RFPrequest for proposal independent monitor also filed testimony and a report affirming that the St. Charles Power Station was selected through an objective and fair RFPrequest for proposal that showed no undue preference to any proposal. An evidentiary hearing is scheduled forwas held in April 2016, and subject to regulatory approval byin July 2016 an ALJ issued a final recommendation that the LPSC full notice to proceedcertify that the construction of St. Charles Power Station is expected to bein the public interest. The LPSC issued its order approving certification of St. Charles Power Station in SummerDecember 2016. CommercialConstruction is in progress and commercial operation is estimated to occur by Summer 2019.mid-2019.
UnionLake Charles Power Station Purchase Agreement
In December 2014,November 2016, Entergy Arkansas, Entergy Gulf States Louisiana and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana would acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas would each acquire one power block and a 25% undivided ownership interest in such related assets. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state regulatory and permitting agencies. Under the original terms of the asset purchase agreement, these included regulatory approvals from the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino antitrust law.
In December 2014, Entergy Texas filed its application for Certificate of Convenience and Necessity (CCN) with the PUCT seeking one of the two necessary PUCT approvals of the acquisition. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the CCN filing. In July 2015, Entergy Texas withdrew its rate case and, together with other parties, filed a motion with the PUCT to dismiss
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Entergy Texas’s CCN application. In July 2015, the PUCT granted the motion to dismiss the CCN case. The power block originally allocated to Entergy Texas will be acquired by Entergy New Orleans. The acquisition by Entergy New Orleans replaces the power purchase agreement with Entergy Gulf States Louisiana that the City Council approved in June 2015. In August 2015, Entergy New Orleans filed an application with the City CouncilLPSC seeking authorization to proceed withcertification that the acquisitionpublic convenience and necessity would be served by the construction of the power block and seeking approvalLake Charles Power Station, a nominal 994 megawatt combined-cycle generating unit in Westlake, Louisiana, on land adjacent to the existing Nelson plant in Calcasieu Parish. The current estimated cost of the recoveryLake Charles Power Station is $872 million, including estimated costs of the associatedtransmission interconnection and other related costs. In November 2015 the City CouncilA procedural schedule has been issued, written resolutionswith an evidentiary hearing scheduled for May and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Power Block 1 and related assetsJune 2017. Subject to timely approval by Entergy New Orleans is prudent and in the public interest.
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery. Supplemental testimony was submitted in July 2015 explaining the reallocation of one of the power blocks to Entergy New Orleans and clarifying that Entergy Gulf States Louisiana would own 100% of the capacity and associated energy of two power blocks. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
In January 2015, Entergy Arkansas filed its application with the APSC for approval of the acquisition and cost recovery. A hearing was held in September 2015. In November 2015 the APSC issued an order conditionally approving the acquisition and requesting that Entergy Arkansas file compliance testimony reporting on two minor conditions. In January 2016 the APSC issued an order finding that Entergy Arkansas’s December 2015 compliance filing was substantially compliant with its November 2015 order.
In February 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed a notification and report form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act with the United States Department of Justice (DOJ) and Federal Trade Commission with respect to their planned acquisition of the Union Power Station. Union Power Partners, L.P. (UPP), the seller, also filed a notification and report form in February 2015.
In March 2015 the DOJ requested additional information and documentary material from each of the purchasing companies and UPP. Also in March 2015, UPP, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed an application with the FERC requesting authorization for the transaction. In April 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas made a filing with the FERC for approval of their proposed accounting treatment of the amortization expenses relating to the acquisition adjustment. Filings were made with the FERC in September 2015 replacing Entergy Texas with Entergy New Orleans as an applicant in the filings and providing supplemental information. In the FERC proceeding requesting authorization for the transaction, in December 2015, UPP, Entergy Arkansas, Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, and Entergy New Orleans filed their response to the FERC’s November 2015 request for additional information. The public comment period on the December 2015 filing expired in January 2016. No protests were filed. The LPSC, City Council, and APSC have filed submissions with the FERC urging the FERC to promptly consider and approve the transaction.
Closing of the purchase is expected to be completed promptly following the receipt of FERC approval.other permits and approvals, commercial operation is estimated to occur by mid-2020.
New Nuclear Development
Entergy Louisiana and Entergy Gulf States Louisiana were developing a project option for new nuclear generation at River Bend. In March 2010, Entergy Louisiana and Entergy Gulf States 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. At its June 2012 meeting the LPSC voted to uphold an ALJ recommendation that the request of Entergy Louisiana and Entergy Gulf States Louisiana be declined 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
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engaged in advanced preparation activities prior to certification. The LPSC directed that Entergy Louisiana and Entergy Gulf States Louisiana be permitted to seek recovery of these costs in their upcoming rate case filings that were subsequently filed in February 2013. In the resolution of the rate case proceeding the LPSC provided for an eight-year amortization of costs incurred in connection with the potential development of new nuclear generation at River Bend, without carrying costs, beginning in December 2014, provided, however, that amortization of these costs shall not result in a future rate increase. As of December 31, 2015, Entergy Louisiana has a regulatory asset of $50.4 million on its balance sheet related to these new nuclear generation development costs.
Sources of Capital
Entergy Louisiana’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred membership issuances; and
bank financing under new or existing facilities.
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Entergy Louisiana may refinance, redeem, or otherwise retire debt 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 its bond indentures and other agreements. Entergy Louisiana has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Louisiana’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| $6,154 | | $2,815 | | $19,573 | | $2,359 |
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| $22,503 | | $6,154 | | $2,815 | | $19,573 |
See Note 4 to the financial statements for a description of the money pool.
Effective October 1, 2015, with the completion of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Louisiana assumed the rights and obligations under Entergy Gulf States Louisiana’s credit facility, such that Entergy Louisiana has a single credit facility in the amount of $350 million scheduled to expire in August 2020.2021. The credit facility allows Entergy Louisiana to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2015,2016, there were no cash borrowings and a $3.1$6.4 million letter of credit outstanding under the credit facility. In addition, Entergy Louisiana is party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2015,2016, a $17.1$5.7 million letter of credit was outstanding under Entergy Louisiana’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facility.facilities.
Effective October 1, 2015, with the completion of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, Entergy Louisiana has assumed the rights and obligations under Entergy Gulf States Louisiana’s nuclear fuel lease, including its obligations as they relate to the credit facility of the Entergy Gulf States Louisiana nuclear fuel company variable interest entity. The Entergy Louisiana nuclear fuel company variable interest entities have two separate credit facilities, one in the amount of $100$105 million and one in the amount of $90$85 million, both scheduled to expire in June 2016.May 2019. As of December 31, 2015, $612016, $3.8 million of letters of credit were outstanding under the credit facility to support a like amount of commercial paper issued by the Entergy Louisiana Waterford 3 nuclear fuel company variable interest entity and $0.6 million of letters of creditthere were no cash borrowings outstanding under the credit facility for
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the Entergy Louisiana River Bend nuclear fuel company variable interest entity. See Note 4 to the financial statements for additional discussion of the nuclear fuel company variable interest entity credit facility.
Entergy Louisiana obtained authorizations from the FERC through October 2017 for the following:
short-term borrowings not to exceed an aggregate amount of $450 million at any time outstanding;
long-term borrowings and security issuances; and
long-term borrowings by its nuclear fuel company variable interest entities.
See Note 4 to the financial statements for further discussion of Entergy Louisiana’s short-term borrowing limits.
In September 2015, Entergy Louisiana redeemed its $100 million of 6.95% Series preferred membership interests and Entergy Gulf States Louisiana redeemed its $10 million of 8.25% Series preferred membership interests as part of a multi-step process to effectuate the Entergy Louisiana and Entergy Gulf States Louisiana Business Combination. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” above for further discussion of the business combination.
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. In January 2013, Entergy Louisiana drew $252.5 million from its funded storm reserve escrow account. In April 2013, Entergy Louisiana filed an application withJune 2014 the LPSC relating to Hurricane Isaac system restoration costs. In May 2013, 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 Louisiana’s storm costs, storm reserves, and issuance costs pursuant to Act 55 of the Louisiana Regular Session of 2007 (Louisiana Act 55). The LPSC Staff filed direct testimony in September 2013 concluding that Hurricane Isaac system restoration costs incurred by Entergy Louisiana were reasonable and prudent, subject to proposed minor adjustments which totaled approximately 1% of the company’s costs. Following an evidentiary hearing and recommendations by the ALJ, the LPSC voted in June 2014 to approve a series of orders which (i) quantify the amountquantified $290.8 million of Hurricane Isaac system restoration costs as prudently incurred ($290.8 million);incurred; (ii) determinedetermined $290 million as the level of storm reserves to be re-established ($290 million);re-established; (iii) authorizeauthorized Entergy Louisiana to utilize Louisiana Act 55 financing for Hurricane Isaac system restoration costs; and (iv) grantgranted other requested relief associated with storm reserves and Act 55 financing of Hurricane Isaac system restoration costs. Entergy Louisiana committed to pass on to customers a minimum of $30.8 million of customer benefits through annual customer credits of approximately $6.2 million for five years. Approvals for the Act 55 financings were obtained from the Louisiana Utilities Restoration Corporation (LURC) and the Louisiana State Bond Commission.
In July 2014, Entergy Louisiana issued two series totaling $300 million See Note 2 to the financial statements for a discussion of 3.78% Series first mortgage bonds due April 2025. Entergy Louisiana used the proceeds to re-establish and replenish its storm damage escrow reserves and for general corporate purposes.
In August 2014 the Louisiana Local Government Environmental Facilities and Community Development Authority (LCDA) issued $314.85 million inissuance of bonds under Act 55 of the Louisiana Legislature. From the $309.5 million of bond proceeds loaned by the LCDA to the LURC, the LURC deposited $16 million in a restricted escrow account as a storm damage reserve for Entergy Louisiana and transferred $293.5 million directly to Entergy Louisiana. Entergy Louisiana used the $293.5 million received from the LURC to acquire 2,935,152.69 Class C preferred, non-voting, membership interest units of Entergy Holdings Company LLC, a company wholly-owned and consolidated by Entergy, that carry a 7.5% annual distribution rate. Distributions are payable quarterly commencing on September 15, 2014, 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
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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 $1.75 billion.
Entergy 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 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.
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.
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.
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.
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Retail Rates - Electric
Filings with the LPSC
2013 Rate Cases
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 in February 2013. The filing anticipated Entergy Gulf States Louisiana’s integration into MISO. In the filing Entergy Gulf States Louisiana requested, among other relief:
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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 planplan: 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.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Gulf States Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings to be reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) no change in rates related to test year 2013, except with respect to recovery of the non-fuel MISO-related costs and any changes to the additional capacity revenue requirement; and (6) no increase in rates related to test year 2014, except for those items eligible for recovery outside of the earnings sharing mechanism. Existing depreciation rates willdid not change. Implementation of rate changes for items recoverable outside of the earnings sharing mechanism occurred in December 2014.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Gulf States Louisiana submitted a compliance filing in May 2014 reflecting the effects of the estimated MISO cost recovery mechanism revenue requirement and adjustment of the additional capacity mechanism. In November 2014, Entergy Gulf States Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data. Based on this updated filing, a net increase of $5.8 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings arewere subject to LPSC review in accordance with the review process set forth in Entergy Gulf States Louisiana’s formula rate plan.
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 resulted in no cost of service rate change under the formula rate plan. The filing also reflected an $18.1 million rate increase for the incremental capacity rider. In August 2012, Entergy Louisiana submitted a revised filing that reflected an earned return on common equity
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of 10.38%, which is still within the earnings bandwidth, resulting in no cost of service rate change. The revised filing also indicated 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. Subsequently, in December 2012, Entergy Louisiana submitted a revised evaluation report that reflected 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. In April 2013, Entergy Louisiana and the LPSC staff filed a joint report resolving the 2011 test year formula rate plan and recovery related to the Grand Gulf uprate. This report was approved by the LPSC in April 2013.
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. The filing anticipated Entergy Louisiana’s integration into MISO. In the filing Entergy Louisiana requested, among other relief:
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 planplan: 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
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deadband, and a capacity rider mechanism that would permit recovery of incremental capacity additions approved by the LPSC.
Following a hearing before an ALJ and the ALJ’s issuance of a Report of Proceedings, in December 2013 the LPSC approved an unopposed settlement of the proceeding. The settlement provided for a $10 million rate increase effective with the first billing cycle of December 2014. Major terms of the settlement included approval of a three-year formula rate plan (effective for test years 2014-2016) modeled after the formula rate plan in effect for Entergy Louisiana for 2011, including the following: (1) a midpoint return on equity of 9.95% plus or minus 80 basis points, with 60/40 sharing of earnings outside of the bandwidth; (2) recovery outside of the sharing mechanism for the non-fuel MISO-related costs, additional capacity revenue requirement, extraordinary items, such as the Ninemile 6 project, and certain special recovery items; (3) three-year amortization of costs to achieve savings associated with the human capital management strategic imperative, with savings reflected as they are realized in subsequent years; (4) eight-year amortization of costs incurred in connection with potential development of a new nuclear unit at River Bend, without carrying costs, beginning December 2014, provided, however, that amortization of these costs shall not result in a future rate increase; (5) recovery of non-fuel MISO-related costs and any changes to the additional capacity revenue requirement related to test year 2013 effective with the first billing cycle of December 2014; and (6) a cumulative $30 million cap on cost of service increases over the three-year formula rate plan cycle, except for those items outside of the sharing mechanism. Existing depreciation rates willdid not change.
Pursuant to the rate case settlement approved by the LPSC in December 2013, Entergy Louisiana submitted a compliance filing in May 2014 reflecting the effects of the $10 million agreed-upon increase in formula rate plan revenue, the estimated MISO cost recovery mechanism revenue requirement, and the adjustment of the additional capacity mechanism. In November 2014, Entergy Louisiana submitted an additional compliance filing updating the estimated MISO cost recovery mechanism for the most recent actual data, as well as providing for a refund and prospective reduction in rates for the true-up of the estimated revenue requirement for the Waterford 3 replacement steam generator project. Based on this updated filing, a net increase of $41.6 million in formula rate plan revenue to be collected over nine months was implemented in December 2014. The compliance filings were subject to LPSC review in accordance with the review process set forth in Entergy Louisiana’s formula rate plan. LPSC staff identified five issues, of which one remains in the compliance proceeding. That issue pertains to Entergy Louisiana’s method of collecting the agreed-upon $10 million increase. No procedural schedule has been established, however, to address the issue. By stipulation among the parties, the final issue raised by the LPSC staff regarding the appropriate level of refunds related to the Waterford 3 replacement steam generator project will be resolved in connection with the Waterford 3 prudence review proceedings discussed below.
2014 Formula Rate Plan Filing
In connection with the approval of the business combination of Entergy Gulf States Louisiana and Entergy Louisiana, the LPSC authorized the filing of a single, joint, formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue was required. The following adjustments were required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism, to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implemented with the first billing cycle of December 2015, subject to refund.
2015 Formula Rate Plan Filing
In May 2016, Entergy Louisiana filed its formula rate plan evaluation report for its 2015 calendar year operations. The evaluation report reflects an earned return on common equity of 9.07%. As such, no adjustment to base formula rate plan revenue is required. The following other adjustments, however, are required under the formula
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be collected over nine months wasrate plan: an increase in the legacy Entergy Louisiana additional capacity mechanism of $14.2 million; a separate increase in legacy Entergy Louisiana revenue of $10 million primarily to reflect the effects of the termination of the System Agreement; an increase in the legacy Entergy Gulf States Louisiana additional capacity mechanism of $0.5 million; a decrease in legacy Entergy Gulf States Louisiana revenue of $58.7 million primarily to reflect the effects of the termination of the System Agreement; and an increase of $11 million to the MISO cost recovery mechanism. Rates were implemented in December 2014. The compliance filings arewith the first billing cycle of September 2016, subject to LPSC reviewrefund. Following implementation of the as-filed rates in accordance with the review process set forth inSeptember 2016, there have been several interim updates to Entergy Louisiana’s formula rate plan. Additionally,plan, including the adjustmentsmost recent adjustment submitted in December 2016, reflecting implementation of rates made related tothe settlement of the Waterford 3 replacement steam generator project included in the December 2014 compliance filing are subject to final true-up following completion of the LPSC’s determination regarding the prudence of the project. LPSC staff identified five issues, of which two remain. The remaining issues pertainreview described below. Also pursuant to Entergy Louisiana’s methodformula rate plan rider, in November 2016, Entergy Louisiana submitted a request for LPSC authorization to extend the recovery mechanism for net revenues and expenses incurred in connection with Entergy Louisiana’s participation in MISO. The MISO cost recovery mechanism was initially approved on an interim basis to remain in place through the rate effective period of collecting the agreed-upon $10 million increase and the level of recovery of investment related to the Grand Gulf uprate. NoEntergy Louisiana’s test year 2015 formula rate plan filing. A procedural schedule has been established, however, to address these remaining issues. The final issue raised by the LPSC staff pertains to the appropriate level of refunds related to the Waterford 3 replacement steam generator project. That issue will be resolvedincluding a hearing in connection with the Waterford 3 prudence review proceedings discussed below.July 2017.
Waterford 3 Replacement Steam Generator Project
Following the completion of the Waterford 3 replacement steam generator project, the LPSC undertook a prudence review in connection with a filing made by Entergy Louisiana in April 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 2014 the LPSC Staff filed testimony recommending potential project and replacement power cost disallowances of up to $71 million, citing a need for further explanation or documentation from Entergy Louisiana. An intervenor filed testimony recommending disallowance of $141 million of incremental project costs, claiming the steam generator fabricator was imprudent. Entergy Louisiana provided further documentation and explanation requested by the LPSC staff. An evidentiary hearing was held in December 2014. At the hearing the parties maintained the positions reflected in pre-filed testimony. Entergy Louisiana believesbelieved that the replacement steam generator costs were prudently incurred and applicable legal principles supportsupported their recovery in rates. Nevertheless, Entergy Louisiana recorded a write-off of $16 million of Waterford 3’s plant balance in December 2014 because of the uncertainty at the time associated with the resolution of the prudence review. In December 2015 the ALJ issued a proposed recommendation, which was subsequently finalized, concluding that Entergy Louisiana prudently managed the Waterford 3 replacement steam generator project, including the selection, use, and oversight of contractors, and could not reasonably have anticipated the damage to the steam generators. Nevertheless, the ALJ concluded that Entergy Louisiana was liable for the conduct of its contractor and subcontractor and, therefore, recommended a disallowance of $67 million in capital costs. Additionally, the ALJ concluded that Entergy Louisiana did not sufficiently justify the incurrence of $2 million in replacement power costs during the replacement outage. Although the ALJ’s recommendation hashad not yet to bebeen considered by the LPSC, after considering the progress of the proceeding in light of the ALJ recommendation, Entergy Louisiana recorded in the fourth quarter 2015 approximately $77 million in charges, including a $45 million asset write-off and a $32 million regulatory charge, to reflect that a portion of the assets associated with the Waterford 3 replacement steam generator project iswas no longer probable of recovery. Entergy Louisiana maintainsmaintained that the ALJ’s recommendation contains significant factual and legal errors.
In October 2016 the parties reached a settlement in this matter. This settlement was approved by the LPSC in December 2016. The settlement effectively provides for an agreed-upon disallowance of $67 million of plant, which had been previously written off by Entergy Louisiana, as discussed above. The settlement also requires a refund of approximately $71 million to be given through a one-time credit included in customers’ bills in January 2017. Of the $71 million of refunds, $68 million was credited to customers through Entergy Louisiana’s formula rate plan, outside of sharing, and $3 million through its fuel adjustment clause. Entergy Louisiana had previously recorded a provision of $48 million for this refund. The previously-recorded provision included the cumulative revenues through December 2016 related to the $67 million of disallowed plant. An additional regulatory charge of $23 million was recorded in fourth quarter 2016 to reflect the effects of the settlement. The settlement also provides that Entergy Louisiana can
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retain the value associated with potential service credits agreed to by the project contractor, to the extent they are realized in the future.
Ninemile 6
In July 2014, Entergy Gulf States Louisiana and Entergy Louisiana filed an unopposed stipulation with the LPSC, which was subsequently approved, that estimated a first year revenue requirement associated with Ninemile 6 and provided a mechanism to update the revenue requirement as the in-service date approached, which was subsequently approved by the LPSC.approached. In late-December 2014, roughly contemporaneous with the unit's placement in service, a final updated estimated revenue requirement of $26.8 million for Entergy Gulf States Louisiana and $51.1 million for Entergy Louisiana was filed. The December 2014 estimate forms the basis of rates implemented effective with the first billing cycle of January 2015. In July 2015, Entergy Louisiana submitted to the LPSC a compliance filing including an estimate at completion, inclusive of interconnection costs and transmission upgrades, of approximately $648 million, or $76 million less than originally estimated, along with other project details and supporting evidence, to enable the LPSC to review the prudence of Entergy Louisiana’s management of the project. A hearingTestimony filed by the LPSC staff generally supports the prudence of the management of the project and recovery of the costs incurred to complete the project. The LPSC staff had questioned the warranty coverage for one element of the project. In October 2016 all parties agreed to a stipulation providing that 100% of Ninemile 6 construction costs was prudently incurred and is scheduledeligible for recovery from customers, but reserving the LPSC’s rights to review the prudence of Entergy Louisiana’s actions regarding one element of the project. This stipulation was approved by the LPSC in March 2016.January 2017.
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Management’s Financial Discussion and Analysis
Union Power Station
In January 2015, Entergy Gulf States Louisiana filed its application with the LPSC for approval of the acquisition and cost recovery of two power blocks of the Union Power Station for an expected base purchase price of approximately $237 million per power block, subject to adjustments. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all parties for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
Business Combination
In connection with the approvalMarch 2016, Entergy Louisiana acquired Power Blocks 3 and 4 of the business combinationUnion Power Station for an aggregate purchase price of Entergy Gulf States Louisianaapproximately $474 million and Entergy Louisiana, the LPSC authorized the filing of a single, joint formula rate plan evaluation report for Entergy Gulf States Louisiana’s and Entergy Louisiana’s 2014 calendar year operations. The joint evaluation report was filed in September 2015 and reflects an earned return on common equity of 9.09%. As such, no adjustment to base formula rate plan revenue is required. The following adjustments are required under the formula rate plan, however: a decrease in the additional capacity mechanism for Entergy Louisiana of $17.8 million; an increase in the additional capacity mechanism for Entergy Gulf States Louisiana of $4.3 million; and a reduction of $5.5 million to the MISO cost recovery mechanism,implemented rates to collect approximately $35.7 million on a combined-company basis. Under the order approving the business combination, following completion of the prescribed review period, rates were implementedestimated first-year revenue requirement with the first billing cycle of December 2015, subjectMarch 2016.
As a term of the LPSC-approved settlement authorizing the purchase of Power Blocks 3 and 4 of the Union Power Station, Entergy Louisiana agreed to refund. make a filing with the LPSC to review its decisions to deactivate Ninemile 3 and Willow Glen 2 and 4 and its decision to retire Little Gypsy 1. In January 2016, Entergy Louisiana made its compliance filing with the LPSC. Entergy Louisiana, LPSC staff, and intervenors participated in a technical conference in March 2016 where Entergy Louisiana presented information on its deactivation/retirement decisions for these four units in addition to information on the current deactivation decisions for the ten-year planning horizon. Parties have requested further proceedings on the prudence of the decision to deactivate Willow Glen 2 and 4. No party contests the prudence of the decision to deactivate Willow Glen 2 and 4 or suggests reactivation of these units; however, issues have been raised related to Entergy Louisiana’s deactivation process. This matter is pending before an ALJ.
Advanced Metering Infrastructure (AMI) Filing
In November 2015,2016, Entergy Louisiana filed an application seeking a finding from the LPSC staff filed objections, corrections,that Entergy Louisiana’s deployment of advanced electric and comments identifying several issuesgas metering infrastructure is in the public interest. Entergy Louisiana proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy Louisiana’s modernized power grid. The filing identified a number of quantified and unquantified benefits,
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and Entergy Louisiana provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $607 million. Entergy Louisiana also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $92 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy Louisiana proposed a 15-year useful life for potential rate adjustments, including: preservationthe new advanced meters, the three-year deployment of previously-raised issues;which is expected to begin in 2019. Assuming LPSC approval is received in 2017, the communications network deployment is expected to begin by late-2018, after the necessary information technology infrastructure is in place. Entergy Louisiana proposed to recover the cost of AMI through the implementation of the $10 million increase in annual formula rate plan revenue over abbreviated rate-effective period; the level of adjustment to rates for the extended power uprate at System Energy, as well as asserting a general reservation of rights for further review of adjustments related to Ninemile 6 and the Waterford 3 provision for rate refund; change to gross plant, depreciation, andcustomer charge, net plant components of rate base; regulatory debits and credits; adjustment for business combination expenses and the implementation of certain guaranteed customer credits. See “Entergy Louisiana and Entergy Gulf States Louisiana Business Combination” above for further discussion ofbenefits, phased in over the business combination.period 2019 through 2022.
Filings with the City Council
In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request made in February 2013. In January 2014, the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity
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Management’s Financial Discussion and Analysis
cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area.
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million, subject to closing adjustments.million. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million.
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. In March 2013 the LPSC staff issued its proposed findings and recommended two adjustments. Entergy Gulf States Louisiana and the LPSC staff reached agreement regarding the LPSC staff’s proposed adjustments. As reflected in an unopposed joint report of proceedings filed by Entergy Gulf States Louisiana and the LPSC staff in May 2013, Entergy Gulf States Louisiana accepted, with modification, the LPSC staff’s proposed adjustment to property insurance expense and agreed to: (1) a three-year extension of the gas rate stabilization plan with a midpoint return on equity of 9.95%, with a first year midpoint reset; (2) dismissal of a docket initiated by the LPSC to evaluate the allowed return on equity for Entergy Gulf States Louisiana’s gas rate stabilization plan; and (3) presentation to the LPSC by November 2014 by Entergy Gulf States Louisiana and the LPSC staff of their recommendation for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment. The LPSC approved the agreement in May 2013.
In January 2014, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2013. The filing showed an earned return on common equity of 5.47%, which results in a $1.5 million rate increase. In April 2014 the LPSC staff issued a report indicating “that Entergy Gulf States Louisiana has properly determined its earnings for the test year ended September 30, 2013.” The $1.5 million rate increase was implemented effective with the first billing cycle of April 2014.
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Management’s Financial Discussion and Analysis
In accordance with the settlement of Entergy Gulf States Louisiana’s gas rate stabilization plan for the test year ended September 30, 2012, in August 2014, Entergy Gulf States Louisiana submitted for consideration a proposal for implementation of an infrastructure rider to recover expenditures associated with strategic plant investment and relocation projects mandated by local governments. After review by the LPSC staff and inclusion of certain customer safeguards required by the LPSC staff, in December 2014, Entergy Gulf States Louisiana and the LPSC staff submitted a joint settlement for implementation of an accelerated gas pipe replacement program providing for the replacement of approximately 100 miles of pipe over the next ten years, as well as relocation of certain existing pipe resulting from local government-related infrastructure projects, and for a rider to recover the investment associated with these projects. The rider allows for recovery of approximately $65 million over ten years. The rider recovery will be adjusted on a quarterly basis to include actual investment incurred for the prior quarter and is subject to the following conditions, among others: a ten-year term; application of any earnings in excess of 10.45% as an offset to the revenue requirement of the infrastructure rider; adherence to a specified spending plan, within plus or minus 20% annually; annual filings comparing actual versus planned rider spending with actual spending and explanation of variances exceeding 10%; and an annual true-up. The joint settlement was approved by the LPSC in January 2015. Implementation of the infrastructure rider commenced with bills rendered on and after the first billing cycle of April 2015.
In January 2015, Entergy Gulf States Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2014. The filing showed an earned return on common equity of 7.20%, which resulted in
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Management’s Financial Discussion and Analysis
a $706 thousand rate increase. In April 2015 the LPSC issued findings recommending two adjustments to Entergy Gulf States Louisiana’s as-filed results, and an additional recommendation that does not affect current year results. The LPSC staff’s recommended adjustments increase the earned return on equity for the test year to 7.24%. Entergy Gulf States Louisiana accepted the LPSC staff’s recommendations and a revenue increase of $688 thousand was implemented with the first billing cycle of May 2015.
In January 2016, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2015. The filing showed an earned return on common equity of 10.22%, which is within the authorized bandwidth, therefore requiring no change in rates. Absent approval of an extension byIn March 2016 the LPSC test yearstaff issued its report stating that the 2015 is the final year under the current gas rate stabilization plan.plan filing was in compliance with the exception of several issues that required additional information, explanation, or clarification for which the LPSC staff had reserved the right to further review. In July 2016 the parties to the proceeding filed an unopposed joint report and motion for entry of order accepting the report that indicates no outstanding issues remained in the filing. In February 2016, however, Entergy Louisiana filed a motion requesting to extend the termsterm of the gas rate stabilization plan in substantially similar form for an additional three-year term.term and included a request for sharing of non-jurisdictional compressed natural gas revenues. Following discovery and the filing of testimony by the LPSC Staff, Entergy Louisiana and the LPSC submitted a joint motion for hearing an uncontested stipulated settlement resolving the proceeding. A hearing on the stipulation was held in November 2016. The ALJ issued a report of proceedings that was presented with the parties’ stipulation to the LPSC for consideration. The stipulation approving Entergy Louisiana’s requested extension of the rate stabilization plan was approved by the LPSC in December 2016.
In January 2017, Entergy Louisiana filed with the LPSC its gas rate stabilization plan for the test year ended September 30, 2016. The filing of the evaluation report for test year 2016 reflects an earned return on common equity of 6.37%. As part of the filing, pursuant to the extraordinary cost provision of the rate stabilization plan, Entergy Louisiana is seeking to recover approximately $1.5 million in deferred operation and maintenance expenses incurred to restore service and repair damage resulting from flooding and widespread rainfall in southeast Louisiana that occurred in August 2016. Entergy Louisiana seeks to recover the prudently incurred August 2016 storm restoration costs over ten years, outside of the rate stabilization plan sharing provisions. As a result, Entergy Louisiana’s filing seeks an annual increase in revenue of $1.4 million. The filing is subject to review by the LPSC staff with resulting rates to be implemented with the first billing cycle of May 2017.
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Management’s Financial Discussion and Analysis
Fuel and purchased power recovery
Entergy Louisiana recovers 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 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 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 million from Entergy Louisiana’s fuel adjustment clause to base rates. The recommended refund was made by Entergy Louisiana in May 2013 in the form of a credit to customers through its fuel adjustment clause filing. Two parties intervened in the proceeding. A procedural schedule was established for the identification of issues by the intervenors and for Entergy Louisiana to submit comments regarding the LPSC Staff report and any issues raised by intervenors. One intervenor is seekingsought further proceedings regarding certain issues it raised in its comments on the LPSC Staffstaff report. Entergy Louisiana has filed responses to both the LPSC Staffstaff report and the issues raised by the intervenor. As required by the procedural schedule, a joint status report was submittedAfter conducting additional discovery, in October 2013 by the parties. A status conference was held in December 2013. Discovery has ceased and the parties are awaiting issuance of the audit report ofApril 2016 the LPSC staff butconsultant issued its supplemental audit report, which concluded that Entergy Louisiana was not imprudent on the issues raised by the intervenor. The intervenor has stated that it does not intend to pursue these issues further. In October 2016 the LPSC staff filed testimony affirming the recommendation in its audit report on the lone remaining issue that nuclear dry fuel storage costs should be realigned to base rates. The parties agreed to remove that remaining issue to a separate docket because the same issue is outstanding the Entergy Gulf States Louisiana audit for the same time period. In November 2016, the LPSC approved the resolution of this audit and the creation of a new docket for the resolution of the proper method of recovery for nuclear dry fuel storage costs. In December 2016 the LPSC opened a new docket in order to resolve the issue regarding the proper methodology for the recovery of nuclear dry fuel storage costs. A procedural schedule has not been established.established for this new docket, including an evidentiary hearing in June 2017.
In December 2011 the LPSC authorized its staff to initiate anothera 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 has ceased and the parties are awaiting issuance of the audit report ofIn March 2016 the LPSC staff consultant issued its audit report. In its report, the LPSC staff consultant recommended that Entergy Louisiana refund approximately $8.6 million, plus interest, to customers and realign the recovery of approximately $12.7 million from Entergy Gulf States Louisiana’s fuel adjustment clause to base rates. In September 2016 the LPSC staff filed testimony stating that is was no longer recommending a disallowance of $3.4 million of the $8.6 million discussed above, but otherwise maintained positions from its report. Subsequently, the parties entered into a procedural schedule has not been established.settlement, which was approved by the LPSC in November 2016. The settlement recognizes the dry cask storage recovery method issue will be addressed in the separate proceeding opened by the LPSC, and provides for a refund of $5 million to legacy Entergy Gulf States Louisiana customers and resolves all other issues raised in the audit.
In July 2014 the LPSC authorized its staff to initiate an audit of Entergy Gulf States Louisiana’s fuel adjustment clause filings. The audit includes a review of the reasonableness of charges flowed by Entergy Gulf States Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.
In July 2014 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 by Entergy Louisiana through its fuel adjustment clause for the period from 2010 through 2013. Discovery commenced in July 2015.
In June 2016 the LPSC staff provided notice of an audit of Entergy Louisiana’s fuel adjustment clause filings and purchased gas adjustment clause filings. In recognition of the business combination that occurred in 2015, the audit notice was issued to Entergy Louisiana and will also include a review of charges to legacy Entergy Gulf States Louisiana customers prior to the business combination. The audit includes a review of the reasonableness of charges
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flowed through Entergy Louisiana’s fuel adjustment clause for the period from 2014 through 2015 and charges flowed through Entergy Louisiana’s purchased gas adjustment clause for the period from 2012 through 2015. Discovery has not commenced.
Other dockets
In March 2016 the LPSC opened two dockets to examine, on a generic basis, issues that it identified in connection with its review of Cleco Corporation’s acquisition by third party investors. The first docket is captioned “In re: Investigation of double leveraging issues for all LPSC-jurisdictional utilities,” and the second is captioned “In re: Investigation of tax structure issues for all LPSC-jurisdictional utilities.” In April 2016 the LPSC clarified that the concerns giving rise to the two dockets arose as a result of its review of the structure of the recently-approved Cleco-Macquarie transaction and that the specific intent of the directives is to seek more information regarding intra-corporate debt financing of a utility’s capital structure as well as the use of investment tax credits to mitigate the tax obligation at the parent level of a consolidated entity. No schedule has been set for either docket, but discovery has commenced.
Industrial and Commercial Customers
Entergy 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 Louisiana’s industrial customer base. Entergy Louisiana responds by working with industrial and commercial customers and negotiating electric service
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Management’s Financial Discussion and Analysis
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.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization” and “System Agreement” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
Entergy Louisiana owns and, through an affiliate, operates the River Bend and Waterford 3 nuclear power plants. Entergy Louisiana 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 River Bend or Waterford 3, Entergy Louisiana may be required to provide additional funds or credit support to satisfy regulatory requirements for decommissioning. Waterford 3’s operating license is currently due to expire in December 2024. In March 2016, Entergy Louisiana filed an application with the NRC for an extension of Waterford 3’s operating license to 2044.
In 2016, Entergy conducted a comprehensive evaluation of the Entergy nuclear fleet and determined that it is necessary to increase investments in its nuclear plants to position the fleet to meet its operational goals. These investments will result in increased operating and capital costs associated with operating Entergy’s nuclear plants going forward. The preliminary estimates of the increase to planned capital costs for 2017 through 2019 identified through and associated with this initiative are estimated to be $315 million for Entergy Louisiana. The current estimates of the capital costs identified through this initiative are included in Entergy Louisiana’s capital investment plan preliminary estimate for 2017 through 2019 given in “Liquidity and Capital Resources - Uses of Capital” above. The increase to planned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $55 million in 2017 for Entergy Louisiana, with a similar level of expenses
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Management’s Financial Discussion and Analysis
expected to continue going forward. In addition, nuclear refueling outage expenses are expected to increase going forward.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.plant systems. The issue is applicable at all nuclear units to River Bend and Waterford 3varying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
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 to undertake plant modifications and perform additional analyses that will, among other things, result in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. Entergy Louisiana’s estimated capital expenditures for 2016 through 2018 for complying with the NRC orders are included in the planned construction and other capital investments estimates given in “Liquidity and Capital Resources - Uses of Capital” above.
Environmental Risks
Entergy 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 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’s financial statements in conformity with generally accepted accounting principles requires management to apply appropriate accounting policies and to make estimates and judgments that
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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’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.
In the fourth quarter 2015, 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 $24.9 million increase in its decommissioning cost liability, along with a corresponding increase in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
In the fourth quarter 2014, Entergy Louisiana recorded a revision to its estimated decommissioning cost liability for River Bend as a result of a revised decommissioning cost study. The revised estimate resulted in a $20 million increaseUtility Regulatory Accounting
See “Utility Regulatory Accounting” in the decommissioning cost liability, along with a corresponding increase in“Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the related asset retirement cost asset that will be depreciated over the remaining useful lifeeffects of the unit.rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements, “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the estimates associated with the unbilled revenue amounts.
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Management’s Financial Discussion and Analysis
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the “Critical Accounting Estimates” section of the revenues earnedEntergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis 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.further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Louisiana’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in 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.
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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 2015 Qualified Pension Cost | | Impact on 2015 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $5,347 | | $51,729 | | (0.25%) | | $4,115 | |
| $53,261 |
|
| Rate of return on plan assets | | (0.25%) | | $2,752 | | $— | | (0.25%) | | $3,068 | | $- |
|
| Rate of increase in compensation | | 0.25% | | $1,936 | | $8,601 | | 0.25% | | $1,600 | |
| $9,232 |
|
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 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,001 | | $11,600 | | (0.25%) | |
| $842 |
| |
| $10,567 |
|
| Health care cost trend | | 0.25% | | $1,662 | | $9,687 | | 0.25% | |
| $1,413 |
| |
| $9,025 |
|
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 20152016 was $72.9$47.1 million. Entergy Louisiana anticipates 20162017 qualified pension cost to be $47.1$44.3 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $14.2 million. Entergy Louisiana contributed $89.4$84.4 million to its pension plans in 20152016 and estimates 2016-2018 pension contributions will approximate $240.2 million, including $83.9be approximately $87.7 million in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total postretirement health care and life insurance benefit costs for Entergy Louisiana in 20152016 were $25.9$15.7 million. Entergy Louisiana expects 20162017 postretirement health care and life insurance benefit costs of approximately $15.7
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
$12.6 million. In 2016, Entergy Louisiana refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $3.5 million. Entergy Louisiana contributed $17.3$16.6 million to its other postretirement plans in 20152016 and expects 2016-2018estimates that 2017 contributions to approximate $58.2 million, including $18.9 million in 2016.will be approximately $19.3 million.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $121.6 million in the qualified pension benefit obligation and $21.5 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $18.1 million and other postretirement cost by approximately $2.8 million. Pension funding guidelines,
Entergy Louisiana, LLC and Subsidiaries
Management’s Financial Discussion and Analysis
as established byIn 2016, the Employee Retirement Income Security Act of 1974, as amended andmortality projection scale was updated to MP-2016, with no change in the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries newbase mortality assumptions until after 2015, possibly 2016.table assumption.
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.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Members of
Entergy Louisiana, LLC and Subsidiaries
Jefferson, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy Louisiana, LLC and Subsidiaries (the “Company”) as of December 31, 20152016 and 20142015 and the related consolidated income statements, and consolidated statements of comprehensive income, cash flows, and changes in equity (pages 353 through 358 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 Louisiana, LLC and Subsidiaries as of December 31, 20152016 and 2014,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, on October 1, 2015 the Company completed a business combination with Entergy Gulf States Louisiana, L.L.C. under which it acquired substantially all of the assets and assumed substantially all of the liabilities of Entergy Gulf States Louisiana, L.L.C. The combination was accounted for as a transaction between entities under common control. Consequently, the consolidated financial statements presented herein have been retrospectively adjusted to reflect the combined entities for all periods presented.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
(Page left blank intentionally)
352
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $4,361,524 |
| |
| $4,668,814 |
| |
| $4,340,273 |
| |
| $4,126,343 |
| |
| $4,361,524 |
| |
| $4,668,814 |
|
| Natural gas | | 55,622 |
| | 71,690 |
| | 59,238 |
| | 50,705 |
| | 55,622 |
| | 71,690 |
|
| TOTAL | | 4,417,146 |
| | 4,740,504 |
| | 4,399,511 |
| | 4,177,048 |
| | 4,417,146 |
| | 4,740,504 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 850,869 |
| | 1,029,793 |
| | 857,581 |
| | 804,433 |
| | 850,869 |
| | 1,029,793 |
|
| Purchased power | | 1,129,910 |
| | 1,508,104 |
| | 1,414,052 |
| | 890,058 |
| | 1,129,910 |
| | 1,508,104 |
|
| Nuclear refueling outage expenses | | 44,480 |
| | 51,790 |
| | 54,911 |
| | 51,361 |
| | 44,480 |
| | 51,790 |
|
| Other operation and maintenance | | 997,546 |
| | 907,308 |
| | 878,755 |
| | 923,779 |
| | 997,546 |
| | 907,308 |
|
| Decommissioning | | 43,445 |
| | 41,493 |
| | 37,520 |
| | 46,944 |
| | 43,445 |
| | 41,493 |
|
| Taxes other than income taxes | | 167,966 |
| | 159,594 |
| | 154,548 |
| | 165,665 |
| | 167,966 |
| | 159,594 |
|
| Depreciation and amortization | | 437,036 |
| | 408,073 |
| | 393,716 |
| | 451,290 |
| | 437,036 |
| | 408,073 |
|
| Other regulatory charges (credits) - net | | 27,562 |
| | (43,484 | ) | | 5,697 |
| | 44,131 |
| | 27,562 |
| | (43,484 | ) |
| TOTAL | | 3,698,814 |
| | 4,062,671 |
| | 3,796,780 |
| | 3,377,661 |
| | 3,698,814 |
| | 4,062,671 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 718,332 |
| | 677,833 |
| | 602,731 |
| | 799,387 |
| | 718,332 |
| | 677,833 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 19,192 |
| | 46,240 |
| | 39,606 |
| | 27,925 |
| | 19,192 |
| | 46,240 |
|
| Interest and investment income | | 150,168 |
| | 134,885 |
| | 144,552 |
| | 154,778 |
| | 150,168 |
| | 134,885 |
|
| Miscellaneous - net | | (13,190 | ) | | 850 |
| | (15,557 | ) | | (11,597 | ) | | (13,190 | ) | | 850 |
|
| TOTAL | | 156,170 |
| | 181,975 |
| | 168,601 |
| | 171,106 |
| | 156,170 |
| | 181,975 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 259,894 |
| | 253,455 |
| | 234,647 |
| | 273,283 |
| | 259,894 |
| | 253,455 |
|
| Allowance for borrowed funds used during construction | | (10,702 | ) | | (24,721 | ) | | (16,137 | ) | | (14,571 | ) | | (10,702 | ) | | (24,721 | ) |
| TOTAL | | 249,192 |
| | 228,734 |
| | 218,510 |
| | 258,712 |
| | 249,192 |
| | 228,734 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 625,310 |
| | 631,074 |
| | 552,822 |
| | 711,781 |
| | 625,310 |
| | 631,074 |
|
| | | | �� | | | | | | | | | |
| Income taxes | | 178,671 |
| | 185,052 |
| | 138,696 |
| | 89,734 |
| | 178,671 |
| | 185,052 |
|
| | | | | | | | | | | | | |
| NET INCOME | | 446,639 |
| | 446,022 |
| | 414,126 |
| | 622,047 |
| | 446,639 |
| | 446,022 |
|
| | | | | | | | | | | | | |
| Preferred distribution requirements and other | | 5,737 |
| | 7,796 |
| | 7,775 |
| | — |
| | 5,737 |
| | 7,796 |
|
| | | | | | | | | | | | | |
| EARNINGS APPLICABLE TO COMMON EQUITY | |
| $440,902 |
| |
| $438,226 |
| |
| $406,351 |
| |
| $622,047 |
| |
| $440,902 |
| |
| $438,226 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| Net Income | |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
| |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
|
| | | | | | | | | | | | | |
| Other comprehensive income (loss) | | |
| | |
| | |
| | |
| | |
| | |
|
| Pension and other postretirement liabilities | | |
| | |
| | |
| | |
| | |
| | |
|
| (net of tax expense (benefit) of $14,316, ($25,984), and $64,717) | | 22,811 |
| | (41,386 | ) | | 73,524 |
| |
| (net of tax expense (benefit) of $5,034, $14,316, and ($25,984)) | | | 7,970 |
| | 22,811 |
| | (41,386 | ) |
| Other comprehensive income (loss) | | 22,811 |
| | (41,386 | ) | | 73,524 |
| | 7,970 |
| | 22,811 |
| | (41,386 | ) |
| | | | | | | | | | | | | |
| Comprehensive Income | |
| $469,450 |
| |
| $404,636 |
| |
| $487,650 |
| |
| $630,017 |
| |
| $469,450 |
| |
| $404,636 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
| |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 593,635 |
| | 580,742 |
| | 560,753 |
| | 620,211 |
| | 593,635 |
| | 580,742 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 97,461 |
| | 248,686 |
| | 397,089 |
| | 178,549 |
| | 97,461 |
| | 248,686 |
|
| Changes in working capital: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | (12,795 | ) | | 101,965 |
| | (175,682 | ) | | (102,200 | ) | | (12,795 | ) | | 101,965 |
|
| Fuel inventory | | (887 | ) | | 2,708 |
| | 684 |
| | (2,693 | ) | | (887 | ) | | 2,708 |
|
| Accounts payable | | 23,641 |
| | (28,422 | ) | | (11,454 | ) | | (36,720 | ) | | 23,641 |
| | (28,422 | ) |
| Prepaid taxes and taxes accrued | | 105,687 |
| | 183,313 |
| | (219,595 | ) | | (235,246 | ) | | 105,687 |
| | 183,313 |
|
| Interest accrued | | 2,933 |
| | 3,567 |
| | 5,179 |
| | 1,218 |
| | 2,933 |
| | 3,567 |
|
| Deferred fuel costs | | 4,222 |
| | 40,245 |
| | 46,387 |
| | (17,023 | ) | | 4,222 |
| | 40,245 |
|
| Other working capital accounts | | (41,890 | ) | | 17,761 |
| | 36,259 |
| | 6,462 |
| | (41,890 | ) | | 17,761 |
|
| Changes in provisions for estimated losses | | (8,946 | ) | | 274,349 |
| | (248,825 | ) | | 490 |
| | (8,946 | ) | | 274,349 |
|
| Changes in other regulatory assets | | 130,762 |
| | (314,837 | ) | | 234,303 |
| | 57,579 |
| | 130,762 |
| | (314,837 | ) |
| Changes in other regulatory liabilities | | 96,234 |
| | 29,713 |
| | 212,431 |
| | 62,351 |
| | 96,234 |
| | 29,713 |
|
| Changes in pension and other postretirement liabilities | | (98,695 | ) | | 299,319 |
| | (321,244 | ) | | (52,559 | ) | | (98,695 | ) | | 299,319 |
|
| Other | | (182,485 | ) | | (166,540 | ) | | 167,087 |
| | (64,554 | ) | | (182,485 | ) | | (166,540 | ) |
| Net cash flow provided by operating activities | | 1,155,516 |
| | 1,718,591 |
| | 1,097,498 |
| | 1,037,912 |
| | 1,155,516 |
| | 1,718,591 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (845,227 | ) | | (757,376 | ) | | (978,592 | ) | | (1,030,416 | ) | | (845,227 | ) | | (757,376 | ) |
| Allowance for equity funds used during construction | | 19,192 |
| | 46,240 |
| | 39,606 |
| | 27,925 |
| | 19,192 |
| | 46,240 |
|
| Insurance proceeds | | | 10,564 |
| | — |
| | — |
|
| Nuclear fuel purchases | | (244,040 | ) | | (172,297 | ) | | (192,192 | ) | | (73,618 | ) | | (244,040 | ) | | (172,297 | ) |
| Proceeds from the sale of nuclear fuel | | 54,595 |
| | 126,004 |
| | 42,839 |
| | 63,304 |
| | 54,595 |
| | 126,004 |
|
| Payment for purchase of plant | | | (474,670 | ) | | — |
| | — |
|
| Investment in affiliates | | — |
| | (293,516 | ) | | — |
| | — |
| | — |
| | (293,516 | ) |
| Payments to storm reserve escrow account | | (308 | ) | | (268,576 | ) | | (29 | ) | | — |
| | (308 | ) | | (268,576 | ) |
| Receipts from storm reserve escrow account | | — |
| | — |
| | 252,483 |
| |
| Changes in securitization account | | (137 | ) | | 1,480 |
| | (157 | ) | | 351 |
| | (137 | ) | | 1,480 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 123,474 |
| | 216,688 |
| | 303,648 |
| | 219,182 |
| | 123,474 |
| | 216,688 |
|
| Investment in nuclear decommissioning trust funds | | (158,028 | ) | | (245,446 | ) | | (334,895 | ) | | (257,209 | ) | | (158,028 | ) | | (245,446 | ) |
| Changes in money pool receivable - net | | (3,339 | ) | | 16,758 |
| | (10,140 | ) | | (16,349 | ) | | (3,339 | ) | | 16,758 |
|
| Proceeds from sale of assets | | 59,610 |
| | — |
| | — |
| | — |
| | 59,610 |
| | — |
|
| Other | | — |
| | — |
| | (22 | ) | |
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 57,934 |
| | — |
| | — |
|
| Changes in other investments - net | | | (1,063 | ) | | — |
| | — |
|
| Net cash flow used in investing activities | | (994,208 | ) | | (1,330,041 | ) | | (877,451 | ) | | (1,474,065 | ) | | (994,208 | ) | | (1,330,041 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 77,172 |
| | 751,565 |
| | 487,510 |
| | 2,450,063 |
| | 77,172 |
| | 751,565 |
|
| Retirement of long-term debt | | (180,595 | ) | | (512,180 | ) | | (105,846 | ) | | (1,488,870 | ) | | (180,595 | ) | | (512,180 | ) |
| Redemption of preferred membership interests | | (110,286 | ) | | — |
| | — |
| | — |
| | (110,286 | ) | | — |
|
| Change in money pool payable - net | | — |
| | — |
| | (7,074 | ) | |
| Changes in credit borrowings - net | | 14,322 |
| | 28,310 |
| | (36,934 | ) | | (56,562 | ) | | 14,322 |
| | 28,310 |
|
| Distributions paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common equity | | (226,000 | ) | | (487,502 | ) | | (476,154 | ) | | (285,500 | ) | | (226,000 | ) | | (487,502 | ) |
| Preferred membership interests | | (6,082 | ) | | (7,775 | ) | | (7,775 | ) | | — |
| | (6,082 | ) | | (7,775 | ) |
| Other | | (15,253 | ) | | 19,960 |
| | 42 |
| | (4,230 | ) | | (15,253 | ) | | 19,960 |
|
| Net cash flow used in financing activities | | (446,722 | ) | | (207,622 | ) | | (146,231 | ) | |
| Net cash flow provided by (used in) financing activities | | | 614,901 |
| | (446,722 | ) | | (207,622 | ) |
| Net increase (decrease) in cash and cash equivalents | | (285,414 | ) | | 180,928 |
| | 73,816 |
| | 178,748 |
| | (285,414 | ) | | 180,928 |
|
| Cash and cash equivalents at beginning of period | | 320,516 |
| | 139,588 |
| | 65,772 |
| | 35,102 |
| | 320,516 |
| | 139,588 |
|
| Cash and cash equivalents at end of period | |
| $35,102 |
| |
| $320,516 |
| |
| $139,588 |
| |
| $213,850 |
| |
| $35,102 |
| |
| $320,516 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $243,745 |
| |
| $241,436 |
| |
| $221,139 |
| |
| $324,456 |
| |
| $243,745 |
| |
| $241,436 |
|
| Income taxes | |
| $89,124 |
| |
| ($242,420 | ) | |
| ($28,558 | ) | |
| $156,605 |
| |
| $89,124 |
| |
| ($242,420 | ) |
| Non-cash financing activities: | | | | | | | | | | | | |
| Capital contribution from parent | |
| ($267,826 | ) | |
| $— |
| |
| $— |
| |
| $— |
| |
| ($267,826 | ) | |
| $— |
|
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $348 |
| |
| $53,825 |
| |
| $49,972 |
| |
| $348 |
|
| Temporary cash investments | | 34,754 |
| | 266,691 |
| | 163,878 |
| | 34,754 |
|
| Total cash and cash equivalents | | 35,102 |
| | 320,516 |
| | 213,850 |
| | 35,102 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 179,051 |
| | 191,131 |
| | 213,517 |
| | 179,051 |
|
| Allowance for doubtful accounts | | (4,209 | ) | | (1,609 | ) | | (6,277 | ) | | (4,209 | ) |
| Associated companies | | 94,418 |
| | 93,195 |
| | 155,794 |
| | 94,418 |
|
| Other | | 56,793 |
| | 27,529 |
| | 54,186 |
| | 56,793 |
|
| Accrued unbilled revenues | | 143,079 |
| | 142,752 |
| | 159,176 |
| | 143,079 |
|
| Total accounts receivable | | 469,132 |
| | 452,998 |
| | 576,396 |
| | 469,132 |
|
| Accumulated deferred income taxes | | — |
| | 53,463 |
| |
| Fuel inventory | | 48,045 |
| | 47,158 |
| | 50,738 |
| | 48,045 |
|
| Materials and supplies - at average cost | | 282,688 |
| | 275,532 |
| | 294,421 |
| | 282,688 |
|
| Deferred nuclear refueling outage costs | | 66,984 |
| | 30,483 |
| | 22,535 |
| | 66,984 |
|
| Prepaid taxes | | — |
| | 23,198 |
| | 110,104 |
| | — |
|
| Prepayments and other | | 28,294 |
| | 46,026 |
| | 41,687 |
| | 28,294 |
|
| TOTAL | | 930,245 |
| | 1,249,374 |
| | 1,309,731 |
| | 930,245 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Investment in affiliate preferred membership interests | | 1,390,587 |
| | 1,390,602 |
| | 1,390,587 |
| | 1,390,587 |
|
| Decommissioning trust funds | | 1,042,293 |
| | 1,021,359 |
| | 1,140,707 |
| | 1,042,293 |
|
| Storm reserve escrow account | | 290,422 |
| | 290,114 |
| | 291,485 |
| | 290,422 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 206,293 |
| | 193,621 |
| | 217,494 |
| | 206,293 |
|
| Other | | 14,776 |
| | 14,887 |
| | 28,844 |
| | 14,776 |
|
| TOTAL | | 2,944,371 |
| | 2,910,583 |
| | 3,069,117 |
| | 2,944,371 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 17,629,077 |
| | 17,228,225 |
| | 18,827,532 |
| | 17,629,077 |
|
| Natural gas | | 159,252 |
| | 148,586 |
| | 172,816 |
| | 159,252 |
|
| Property under capital lease | | 341,514 |
| | 334,716 |
| | — |
| | 341,514 |
|
| Construction work in progress | | 420,874 |
| | 369,359 |
| | 670,201 |
| | 420,874 |
|
| Nuclear fuel | | 386,524 |
| | 294,622 |
| | 249,807 |
| | 386,524 |
|
| TOTAL UTILITY PLANT | | 18,937,241 |
| | 18,375,508 |
| | 19,920,356 |
| | 18,937,241 |
|
| Less - accumulated depreciation and amortization | | 8,302,774 |
| | 8,119,158 |
| | 8,420,596 |
| | 8,302,774 |
|
| UTILITY PLANT - NET | | 10,634,467 |
| | 10,256,350 |
| | 11,499,760 |
| | 10,634,467 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 478,243 |
| | 486,269 |
| | 470,480 |
| | 478,243 |
|
| Other regulatory assets (includes securitization property of $114,701 as of December 31, 2015 and $135,538 as of December 31, 2014) | | 1,217,874 |
| | 1,340,610 |
| |
| Other regulatory assets (includes securitization property of $92,951 as of December 31, 2016 and $114,701 as of December 31, 2015) | | | 1,168,058 |
| | 1,217,874 |
|
| Deferred fuel costs | | 168,122 |
| | 168,122 |
| | 168,122 |
| | 168,122 |
|
| Other | | 14,125 |
| | 12,517 |
| | 16,003 |
| | 14,125 |
|
| TOTAL | | 1,878,364 |
| | 2,007,518 |
| | 1,822,663 |
| | 1,878,364 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $17,701,271 |
| |
| $16,387,447 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $29,372 |
| |
| $51,480 |
| |
| $200,198 |
| |
| $29,372 |
|
| Short-term borrowings | | 60,356 |
| | 46,033 |
| | 3,794 |
| | 60,356 |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | | 165,419 |
| | 135,380 |
| | 82,106 |
| | 165,419 |
|
| Other | | 276,280 |
| | 273,203 |
| | 358,741 |
| | 276,280 |
|
| Customer deposits | | 146,555 |
| | 149,759 |
| | 148,601 |
| | 146,555 |
|
| Taxes accrued | | 125,142 |
| | — |
| | — |
| | 125,142 |
|
| Interest accrued | | 74,380 |
| | 71,447 |
| | 75,598 |
| | 74,380 |
|
| Deferred fuel costs | | 65,234 |
| | 61,012 |
| | 48,211 |
| | 65,234 |
|
| Other | | 79,982 |
| | 92,768 |
| | 80,013 |
| | 79,982 |
|
| TOTAL | | 1,022,720 |
| | 881,082 |
| | 997,262 |
| | 1,022,720 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 2,506,956 |
| | 3,007,539 |
| | 2,691,118 |
| | 2,506,956 |
|
| Accumulated deferred investment tax credits | | 131,760 |
| | 137,048 |
| | 126,741 |
| | 131,760 |
|
| Regulatory liability for income taxes - net | | 2,473 |
| | — |
| | — |
| | 2,473 |
|
| Other regulatory liabilities | | 818,623 |
| | 722,389 |
| | 880,974 |
| | 818,623 |
|
| Decommissioning | | 1,027,862 |
| | 950,353 |
| | 1,082,685 |
| | 1,027,862 |
|
| Accumulated provisions | | 310,282 |
| | 319,228 |
| | 310,772 |
| | 310,282 |
|
| Pension and other postretirement liabilities | | 833,185 |
| | 931,988 |
| | 780,278 |
| | 833,185 |
|
| Long-term debt (includes securitization bonds of $120,549 as of December 31, 2015 and $140,782 as of December 31, 2014) | | 4,806,790 |
| | 4,882,813 |
| |
| Long-term debt (includes securitization bonds of $99,217 as of December 31, 2016 and $120,549 as of December 31, 2015) | | | 5,612,593 |
| | 4,806,790 |
|
| Long-term payables - associated companies | | 1,073 |
| | 26,156 |
| | — |
| | 1,073 |
|
| Other | | 188,411 |
| | 218,242 |
| | 137,039 |
| | 188,411 |
|
| TOTAL | | 10,627,415 |
| | 11,195,756 |
| | 11,622,200 |
| | 10,627,415 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| EQUITY | | |
| | |
| | |
| | |
|
| Preferred membership interests without sinking fund | | — |
| | 110,000 |
| |
| Member’s equity | | 4,793,724 |
| | 4,316,210 |
| | 5,130,251 |
| | 4,793,724 |
|
| Accumulated other comprehensive loss | | (56,412 | ) | | (79,223 | ) | | (48,442 | ) | | (56,412 | ) |
| TOTAL | | 4,737,312 |
| | 4,346,987 |
| | 5,081,809 |
| | 4,737,312 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $17,701,271 |
| |
| $16,387,447 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN EQUITY | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | | | | | | | | |
| | | | Common Equity | | | | | Common Equity | | |
| | Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total | Preferred Membership Interests | | Member’s Equity | | Accumulated Other Comprehensive Income (Loss) | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2012 |
| $110,000 |
| |
| $4,454,861 |
| |
| ($111,361 | ) | |
| $4,453,500 |
| |
| Net income | — |
| | 414,126 |
| | — |
| | 414,126 |
| |
| Other comprehensive income | — |
| | — |
| | 73,524 |
| | 73,524 |
| |
| Distributions to parent | — |
| | (376,855 | ) | | — |
| | (376,855 | ) | |
| Distributions declared on common equity | — |
| | (119,900 | ) | | — |
| | (119,900 | ) | |
| Distributions declared on preferred membership interests | — |
| | (7,775 | ) | | — |
| | (7,775 | ) | |
| Other | — |
| | 9 |
| | — |
| | 9 |
| |
| Balance at December 31, 2013 |
| $110,000 |
| |
| $4,364,466 |
| |
| ($37,837 | ) | |
| $4,436,629 |
|
| $110,000 |
| |
| $4,364,466 |
| |
| ($37,837 | ) | |
| $4,436,629 |
|
| Net income | — |
| | 446,022 |
| | — |
| | 446,022 |
| — |
| | 446,022 |
| | — |
| | 446,022 |
|
| Contribution from parent | — |
| | 1,052 |
| | — |
| | 1,052 |
| — |
| | 1,052 |
| | — |
| | 1,052 |
|
| Other comprehensive loss | — |
| | — |
| | (41,386 | ) | | (41,386 | ) | — |
| | — |
| | (41,386 | ) | | (41,386 | ) |
| Distributions to parent | — |
| | (320,601 | ) | | — |
| | (320,601 | ) | — |
| | (320,601 | ) | | — |
| | (320,601 | ) |
| Distributions declared on common equity | — |
| | (166,901 | ) | | — |
| | (166,901 | ) | — |
| | (166,901 | ) | | — |
| | (166,901 | ) |
| Distributions declared on preferred membership interests | — |
| | (7,796 | ) | | — |
| | (7,796 | ) | — |
| | (7,796 | ) | | — |
| | (7,796 | ) |
| Other | — |
| | (32 | ) | | — |
| | (32 | ) | — |
| | (32 | ) | | — |
| | (32 | ) |
| Balance at December 31, 2014 |
| $110,000 |
| |
| $4,316,210 |
| |
| ($79,223 | ) | |
| $4,346,987 |
|
| $110,000 |
| |
| $4,316,210 |
| |
| ($79,223 | ) | |
| $4,346,987 |
|
| Net income | — |
| | 446,639 |
| | — |
| | 446,639 |
| — |
| | 446,639 |
| | — |
| | 446,639 |
|
| Other comprehensive loss | — |
| | — |
| | 22,811 |
| | 22,811 |
| |
| Other comprehensive income | | — |
| | — |
| | 22,811 |
| | 22,811 |
|
| Preferred stock redemption | (110,000 | ) | | — |
| | — |
| | (110,000 | ) | (110,000 | ) | | — |
| | — |
| | (110,000 | ) |
| Non-cash contribution from parent | — |
| | 267,826 |
| | — |
| | 267,826 |
| — |
| | 267,826 |
| | — |
| | 267,826 |
|
| Distributions to parent | — |
| | (226,000 | ) | | — |
| | (226,000 | ) | — |
| | (226,000 | ) | | — |
| | (226,000 | ) |
| Distributions declared on preferred membership interests | — |
| | (5,737 | ) | | — |
| | (5,737 | ) | — |
| | (5,737 | ) | | — |
| | (5,737 | ) |
| Other | — |
| | (5,214 | ) | | — |
| | (5,214 | ) | — |
| | (5,214 | ) | | — |
| | (5,214 | ) |
| Balance at December 31, 2015 |
| $— |
| |
| $4,793,724 |
| |
| ($56,412 | ) | |
| $4,737,312 |
|
| $— |
| |
| $4,793,724 |
| |
| ($56,412 | ) | |
| $4,737,312 |
|
| Net income | | — |
| | 622,047 |
| | — |
| | 622,047 |
|
| Other comprehensive loss | | — |
| | — |
| | 7,970 |
| | 7,970 |
|
| Distributions to parent | | — |
| | (285,500 | ) | | — |
| | (285,500 | ) |
| Other | | — |
| | (20 | ) | | — |
| | (20 | ) |
| Balance at December 31, 2016 | |
| $— |
| |
| $5,130,251 |
| |
| ($48,442 | ) | |
| $5,081,809 |
|
| | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
|
| | ENTERGY LOUISIANA, LLC AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON (a) | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $4,417,146 |
| |
| $4,740,504 |
| |
| $4,399,511 |
| |
| $3,668,755 |
| |
| $4,496,173 |
|
| $4,177,048 |
| |
| $4,417,146 |
| |
| $4,740,504 |
| |
| $4,399,511 |
| |
| $3,668,755 |
|
| Net Income |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
| |
| $440,058 |
| |
| $675,527 |
| |
| Net income | |
| $622,047 |
| |
| $446,639 |
| |
| $446,022 |
| |
| $414,126 |
| |
| $440,058 |
|
| Total assets |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $15,275,863 |
| |
| $14,779,578 |
| |
| $13,771,578 |
|
| $17,701,271 |
| |
| $16,387,447 |
| |
| $16,423,825 |
| |
| $15,275,863 |
| |
| $14,779,578 |
|
Long-term obligations (b)(a) |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $4,383,273 |
| |
| $4,213,537 |
| |
| $3,624,645 |
|
| $5,612,593 |
| |
| $4,806,790 |
| |
| $4,882,813 |
| |
| $4,383,273 |
| |
| $4,213,537 |
|
| | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt).
| | (a) Includes long-term debt (excluding currently maturing debt).
| | | | |
| | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Residential |
| $1,292 |
| |
| $1,358 |
| |
| $1,304 |
| |
| $1,076 |
| |
| $1,309 |
|
| $1,196 |
| |
| $1,292 |
| |
| $1,358 |
| |
| $1,304 |
| |
| $1,076 |
|
| Commercial | 989 |
| | 1,044 |
| | 1,003 |
| | 831 |
| | 965 |
| 930 |
| | 989 |
| | 1,044 |
| | 1,003 |
| | 831 |
|
| Industrial | 1,420 |
| | 1,569 |
| | 1,457 |
| | 1,123 |
| | 1,357 |
| 1,350 |
| | 1,420 |
| | 1,569 |
| | 1,457 |
| | 1,123 |
|
| Governmental | 67 |
| | 70 |
| | 68 |
| | 56 |
| | 64 |
| 67 |
| | 67 |
| | 70 |
| | 68 |
| | 56 |
|
| Total retail |
| $3,768 |
| |
| $4,041 |
| |
| $3,832 |
| |
| $3,086 |
| |
| $3,695 |
| 3,543 |
| | 3,768 |
| | 4,041 |
| | 3,832 |
| | 3,086 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 406 |
| | 427 |
| | 320 |
| | 378 |
| | 552 |
| 368 |
| | 406 |
| | 427 |
| | 320 |
| | 378 |
|
| Non-associated companies | 36 |
| | 80 |
| | 48 |
| | 36 |
| | 60 |
| 50 |
| | 36 |
| | 80 |
| | 48 |
| | 36 |
|
| Other | 152 |
| | 121 |
| | 140 |
| | 120 |
| | 124 |
| 165 |
| | 152 |
| | 121 |
| | 140 |
| | 120 |
|
| Total |
| $4,362 |
| |
| $4,669 |
| |
| $4,340 |
| |
| $3,620 |
| |
| $4,431 |
|
| $4,126 |
| |
| $4,362 |
| |
| $4,669 |
| |
| $4,340 |
| |
| $3,620 |
|
| | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Residential | 14,399 |
| | 14,415 |
| | 14,026 |
| | 13,879 |
| | 14,686 |
| 13,810 |
| | 14,399 |
| | 14,415 |
| | 14,026 |
| | 13,879 |
|
| Commercial | 11,700 |
| | 11,555 |
| | 11,402 |
| | 11,399 |
| | 11,394 |
| 11,478 |
| | 11,700 |
| | 11,555 |
| | 11,402 |
| | 11,399 |
|
| Industrial | 27,713 |
| | 27,025 |
| | 25,734 |
| | 25,306 |
| | 24,854 |
| 28,517 |
| | 27,713 |
| | 27,025 |
| | 25,734 |
| | 25,306 |
|
| Governmental | 756 |
| | 732 |
| | 723 |
| | 707 |
| | 695 |
| 794 |
| | 756 |
| | 732 |
| | 723 |
| | 707 |
|
| Total retail | 54,568 |
| | 53,727 |
| | 51,885 |
| | 51,291 |
| | 51,629 |
| 54,599 |
| | 54,568 |
| | 53,727 |
| | 51,885 |
| | 51,291 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 7,500 |
| | 6,240 |
| | 5,168 |
| | 6,426 |
| | 7,611 |
| 7,345 |
| | 7,500 |
| | 6,240 |
| | 5,168 |
| | 6,426 |
|
| Non-associated companies | 770 |
| | 1,051 |
| | 979 |
| | 1,006 |
| | 1,198 |
| 1,690 |
| | 770 |
| | 1,051 |
| | 979 |
| | 1,006 |
|
| Total | 62,838 |
| | 61,018 |
| | 58,032 |
| | 58,723 |
| | 60,438 |
| 63,634 |
| | 62,838 |
| | 61,018 |
| | 58,032 |
| | 58,723 |
|
| | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | |
| |
| (a) Amounts have been retrospectively adjusted to reflect the effects of the Entergy Louisiana and Entergy Gulf States Louisiana business combination in all periods presented. See Note 1 to the financial statements for a discussion of the business combination. | |
(b) Includes long-term debt (excluding currently maturing debt).
| |
ENTERGY MISSISSIPPI, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2016 Compared to 2015
Net income increased $16.5 million primarily due to lower other operation and maintenance expenses, higher net revenues, and a lower effective income tax rate, partially offset by higher depreciation and amortization expenses.
2015 Compared to 2014
Net income increased $17.9 million primarily due to the write-off in 2014 of the regulatory assets associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, partially offset by higher depreciation and amortization expenses, higher taxes other than income taxes, higher other operation and maintenance expenses, and lower net revenue. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation.
2014Net Revenue
2016 Compared to 20132015
Net income decreased $7.3 millionrevenue 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 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $696.3 |
|
| Retail electric price | 12.9 |
|
| Volume/weather | 4.7 |
|
| Net wholesale revenue | (2.4 | ) |
| Reserve equalization | (2.8 | ) |
| Other | (3.3 | ) |
| 2016 net revenue |
| $705.4 |
|
The retail electric price variance is primarily due to the write-offa $19.4 million net annual increase in 2014 of the regulatory asset associated with new nuclear generation development costsrevenues, as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, effective with the first billing cycle of July 2016, and an increase in which Entergy Mississippi agreed not to pursue recovery ofrevenues collected through the costs deferred by an MPSC order in the new nuclear generation docket.storm damage rider. See Note 2 to the financial statements for more discussion ofon the new nuclear generation development costsformula rate plan and the joint stipulation. Also contributingstorm damage rider.
The volume/weather variance is primarily due to an increase of 153 GWh, or 1%, in billed electricity usage, including an increase in industrial usage, partially offset by the effect of less favorable weather on residential and commercial sales. The increase in industrial usage is primarily due to expansion projects in the pulp and paper industry, increased demand for existing customers, primarily in the metals industry, and new customers in the wood products industry.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
The net wholesale revenue variance is primarily due to Entergy Mississippi’s exit from the System Agreement in November 2015.
The reserve equalization revenue variance is primarily due to the decrease were higher depreciation and amortization expenses and higher taxes other than income taxes. These decreases were significantly offset by higher netabsence of reserve equalization revenue and lower other operation and maintenance expenses.as compared to the same period in 2015 resulting from Entergy Mississippi’s exit from the System Agreement in November 2015.
Net Revenue
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
| 2014 net revenue |
| $701.2 |
|
| Volume/weather | 8.9 |
|
| Retail electric price | 7.3 |
|
| Net wholesale revenue | (2.7 | ) |
| Transmission equalization | (5.4 | ) |
| Reserve equalization | (5.5 | ) |
| Other | (7.5 | ) |
| 2015 net revenue |
| $696.3 |
|
The volume/weather variance is primarily due to an increase of 86 GWh, or 1%, in billed electricity usage,
including the effect of more favorable weather on residential and commercial sales.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
The retail electric price variance is primarily due to a $16 million net annual increase in revenues, effective February 2015, as a result of the MPSC order in the June 2014 rate case and an increase in revenues collected through the energy efficiency rider, partially offset by a decrease in revenues collected through the storm damage rider. The rate case included the realignment of certain costs from collection in riders to base rates. The increase in the energy efficiency rider and the decrease in the storm damage rider are offset by other operation and maintenance expenses and have a minimal effect on net income. See Note 2 to the financial statements for a discussion of the rate case, the energy efficiency rider, and the storm damage rider.
The net wholesale revenue variance is primarily due to a wholesale customer contract termination in October 2015.
Transmission equalization revenue represents amounts received by Entergy Mississippi from certain other Entergy Utility operating companies, in accordance with the System Agreement, to allocate the costs of collectively planning, constructing, and operating Entergy’s bulk transmission facilities. The transmission equalization variance is primarily attributable to the realignment, effective February 2015, of these revenues from the determination of base rates to inclusion in a rider. Such revenues had a favorable effect on net revenue in 2014, but minimal effect in 2015. Entergy Mississippi exited the System Agreement in November 2015. See “System Agreement” inNote 2 to the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysisfinancial statements for a discussion of the System Agreement.
Reserve equalization revenue represents amounts received by Entergy Mississippi from certain other Entergy Utility operating companies, in accordance with the System Agreement, to allocate the costs of collectively maintaining adequate electric generating capacity across the Entergy System. The reserve equalization variance is primarily attributable to the realignment, effective February 2015, of these revenues from the determination of base rates to inclusion in a rider. Such revenues had a favorable effect on net revenue in 2014, but minimal effect in 2015. Entergy Mississippi exited the System Agreement in November 2015. See “System Agreement” 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 the System Agreement.
2014 Compared to 2013
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 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $644.4 |
|
Retail electric price | 39.7 |
|
Reserve equalization | 11.2 |
|
Transmission equalization | 1.3 |
|
Volume/weather | 1.3 |
|
Other | 3.3 |
|
2014 net revenue |
| $701.2 |
|
The retail electric price variance is primarily due to a formula rate plan increase, as approved by the MPSC, effective September 2013 and an increase in the storm damage rider, as approved by the MPSC, effective October 2013. The increase in the storm damage rider is offset by other operation and maintenance expenses and has no effect on net income. See Note 2 to the financial statements for a discussion of the formula rate plan and storm damage rider.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
The reserve equalization variance is primarily due to an increase in reserve equalization revenue primarily due to the changes in the Entergy System generation mix as a result of Entergy Arkansas’s exit fromMississippi exited the System Agreement in December 2013.November 2015. See Note 2 to the financial statements for a discussion of the System Agreement.
The transmission equalization variance isOther Income Statement Variances
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $9.4 million in fossil-fueled generation expenses primarily due to changesa lower scope of work done during plant outages in transmission investment equalization billings under the Entergy System Agreement2016 as compared to the same period in 20132015;
a decrease of $6.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of Entergy Arkansas’s exit froman increase in the System Agreementdiscount rate used to value the benefit liabilities and a refinement in December 2013.the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS - Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
a decrease of $2 million due to lower write-offs of uncollectible customer accounts in 2016;
a decrease of $2 million in energy efficiency costs; and
several individually insignificant items.
The volume/weather variance isdecrease was partially offset by an increase of $7.1 million in storm damage provisions and an increase of $6 million in distribution expenses primarily due to an increase of 86 GWh, or 1%, in billed electricity usage, including the effect of more favorable weather on residential sales as comparedhigher vegetation maintenance. See Note 2 to the prior year and an increase in industrial sales. The increase in industrial usage is primarily in the primary metals and pipelines industries.financial statements for a discussion of storm cost recovery.
Other Income Statement VariancesDepreciation and amortization expenses increased primarily due to additions to plant in service.
2015 Compared to 2014
Other operation and maintenance expenses increased primarily due to:
an increase of $5 million in distribution expenses primarily due to higher vegetation maintenance and higher labor costs in 2015 as compared to 2014;
an increase of $4.9 million in energy efficiency costs. These costs, which began in fourth quarter 2014 and are recovered through the energy efficiency rider having minimal effect on net income;2014;
an increase of $4.8 million in fossil-fueled generation expenses primarily due to a higher scope of work done during plant outages in 2015 as compared to 2014;
a $2.6 million loss recognized on the disposition of plant components;
an increase of $1.8 million in costs incurred in 2014 related to repairs as a result of a unplanned outage event that occurred at the Baxter Wilson (Unit 1) repairs,power plant in September 2013, including an offset for expected insurance proceeds and amortization of the repair costs in 2015 that were deferred in 2014 as approved by the MPSC. See “Baxter Wilson Plant Event” below for a discussion of the Baxter Wilson plant event;MPSC; and
an increase of $1.7 million in compensation and benefits costs primarily due to an increase in net periodic pension and other postretirement benefits costs as a result of lower discount rates and changes in retirement and mortality assumptions, partially offset by a decrease in the accrual for incentive-based compensation. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefitsbenefit costs.
The increase was partially offset by a decrease of $17.6 million in storm damage accruals.provisions. See Note 2 to the financial statements for a discussion of storm cost recovery.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
The asset write-off variance is due to the $56.2 million ($36.7 million after-tax) write-off in 2014 of Entergy Mississippi’s regulatory assets associated with new nuclear generation development costs. See “New Nuclear Generation Development Costs” below and Note 2 to the financial statements for discussion of the new nuclear generation development costs.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service and higher depreciation rates in 2015, as approved by the MPSC.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
2014 Compared to 2013
Other operation and maintenance expenses decreased primarily due to:
a decrease of $11.6 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
a decrease of $7.6 million in fossil-fueled generation expenses primarily due to a lower scope of work done during plant outages in 2014 as compared to the same period in 2013;
a decrease of $5.9 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business;
a decrease of $5.1 million in implementation costs, severance costs, and curtailment and special termination benefits related to the human capital management strategic imperative in 2014 as compared to 2013. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion; and
a net decrease of $3.8 million related to Baxter Wilson (Unit 1) repairs. The increase in repair costs incurred in 2014 compared to the prior year were offset by expected insurance proceeds and the deferral of repair costs, as approved by the MPSC. See “Baxter Wilson Plant Event” below for further discussion.
The decrease was partially offset by:
an increase of $10 million in storm damage accruals, as approved by the MPSC, effective October 2013;
an increase of $5.1 million in 2014 as compared to 2013 in administration fees related to participation in the MISO RTO;
an increase of $4 million in regulatory, consulting, and legal fees;
an increase of $2.3 million in distribution and transmission vegetation maintenance;
an increase of $1.3 million due to higher write-offs of uncollectible customer accounts in 2014 as compared to 2013; and
several individually insignificant items.
The asset write-off resulted from the $56.2 million ($36.7 million after-tax) write-off in 2014 of the regulatory asset associated with new nuclear generation development costs as a result of a joint stipulation entered into with the Mississippi Public Utilities Staff, subsequently approved by the MPSC, in which Entergy Mississippi agreed not to pursue recovery of the costs deferred by an MPSC order in the new nuclear generation docket. See Note 2 to the financial statements for discussion of the new nuclear generation development costs and the joint stipulation.
Taxes other than income taxes increased primarily due to an increase in ad valorem taxes in 2014 as compared to prior year and an increase in local franchise taxes due to higher revenues.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014 and 2013 were 36.9%, 40.0%, 42.7%, and 37.7%42.7%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $145,605 |
| |
| $61,633 |
| |
| $31 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 212,280 |
| | 372,279 |
| | 303,463 |
|
| Investing activities | (289,444 | ) | | (245,127 | ) | | (177,765 | ) |
| Financing activities | 8,393 |
| | (43,180 | ) | | (64,096 | ) |
| Net increase (decrease) in cash and cash equivalents | (68,771 | ) | | 83,972 |
| | 61,602 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $76,834 |
| |
| $145,605 |
| |
| $61,633 |
|
Operating Activities
Net cash flow provided by operating activities decreased $160 million in 2016 primarily due to a decrease due to the timing of recovery of fuel and purchased power costs in 2016 as compared to the same period in 2015 and $15.3 million in insurance proceeds received in 2015 related to the unplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant in September 2013. The decrease was partially offset by income tax refunds of $12.5 million in 2016 compared to income tax payments of $61.3 million in 2015. Entergy Mississippi had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit whereas the income tax payments in 2015 were primarily due to the results of operations and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. See Note 3 to the financial statements for a discussion of the income tax audits.
Net cash flow provided by operating activities increased $68.8 million in 2015 primarily due to:
an increase due to the timing of recovery of fuel and purchased power costs in 2015;
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Baxter Wilson Plant Event
On September 11, 2013, Entergy Mississippi’s Baxter Wilson (Unit 1) power plant experienced a significant unplanned outage event. Entergy Mississippi completed the repairs to the unit in December 2014. As of December 31, 2014, Entergy Mississippi incurred $22.3 million of capital spending and $26.6 million of operation and maintenance expenses to return the unit to service. The damage was covered by Entergy Mississippi’s property insurance policy, subject to a $20 million deductible. As of December 31, 2014, Entergy Mississippi recorded an insurance receivable of $28.2 million for the amount expected to be received from its insurance policy and has received all of its previously-accrued insurance proceeds, with $12.9 million allocated to capital spending and $15.3 million allocated to operation and maintenance expenses. In June 2014, Entergy Mississippi filed a rate case with the MPSC, which includes recovery of the costs associated with Baxter Wilson (Unit 1) repair activities, net of applicable insurance proceeds. In December 2014 the MPSC issued an order that provided for a deferral of $6 million in other operation and maintenance expenses associated with the Baxter Wilson outage and that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset to occur over two years beginning in February 2015, and provided that the capital costs will be reflected in rate base. The final accounting of costs to return the unit to service and insurance proceeds will be addressed in Entergy Mississippi’s next formula rate plan filing.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2015, 2014, and 2013 were as follows:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $61,633 |
| |
| $31 |
| |
| $52,970 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 372,279 |
| | 303,463 |
| | 219,665 |
|
| Investing activities | (245,127 | ) | | (177,765 | ) | | (149,410 | ) |
| Financing activities | (43,180 | ) | | (64,096 | ) | | (123,194 | ) |
| Net increase (decrease) in cash and cash equivalents | 83,972 |
| | 61,602 |
| | (52,939 | ) |
| | | | | | |
| Cash and cash equivalents at end of period |
| $145,605 |
| |
| $61,633 |
| |
| $31 |
|
Operating Activities
Net cash flow provided by operating activities increased $68.8 million in 2015 primarily due to:
increased recovery of fuel costs in 2015;
System Agreement bandwidth remedy payments of $16.4 million made in September 2014 as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;
$15.3 million in insurance proceeds received in 2015 related to the Baxter Wilson plant event. See “Baxter Wilson Plant Event” above for a discussion ofunplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant event;in September 2013; and
the timing of collections from customers.
The increase was partially offset by:
an increase of $41.7 million in income tax payments in 2015. Entergy Mississippi had income tax payments in 2015 and 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 arewere primarily due to the results of operations
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
and the reversal of taxable temporary differences as well as final settlement of amounts outstanding associated with the 2006-2007 IRS audit. The 2014 payments resulted primarily from the reversal of taxable temporary differences for which Entergy Mississippi had previously claimed a tax deduction. See Note 3 to the financial statements for a discussion of this audit; and
System Agreement bandwidth remedy payments of $11.3 million received in 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period.
See Note 2 to the financial statements for a discussion of the System Agreement proceedings.
Investing Activities
Net cash flow provided by operatingused in investing activities increased $83.8$44.3 million in 20142016 primarily due to:
increased recoveryan increase of fuel costs;$72.4 million in transmission construction expenditures primarily due to a higher scope of work performed in 2016 as compared to the same period in 2015;
the timinginsurance proceeds of collections of receivables from customers; and
System Agreement bandwidth remedy payments of $11.3$12.9 million received in 2014 as a result of the compliance filing pursuant to the FERC’s February 2014 orders2015 related to the bandwidth payments/receipts forunplanned outage event that occurred at the June - December 2005 period.Baxter Wilson (Unit 1) power plant in September 2013;
an increase of $11.4 million in distribution construction expenditures primarily due to a higher scope of non-storm related work performed in 2016 as compared to the same period in 2015; and
an increase of $10.1 million due to various information technology projects and upgrades.
The increase was partially offset by:
System Agreement bandwidth remedy payments made in September 2014by a decrease of $16.4 million as a result of the compliance filing pursuant to the FERC’s orders related to the bandwidth payments/receipts for the 2007 - 2009 period;
an increase of $15$20.1 million in income tax paymentsfossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2014. Entergy Mississippi had income tax payments in 2014 and 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2013 and 2014 payments resulted primarily from the reversal of temporary differences for which Entergy Mississippi had previously claimed a tax deduction; and
an increase of $13.7 million in pension contributions in 20142016 as compared to 2013. See “Critical Accounting Estimates” belowthe same period in 2015 and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
money pool activity.
See Note 2Decreases in Entergy Mississippi’s receivable from the money pool are a source of cash flow, and Entergy Mississippi’s receivable from the money pool decreased by $15.3 million in 2016 compared to increasing by $25.3 million in 2015. The money pool is an inter-company borrowing arrangement designed to reduce the financial statementsUtility subsidiaries’ need for a discussion of the System Agreement proceedings.
Investing Activitiesexternal short-term borrowings.
Net cash flow used in investing activities increased $67.4 million in 2015 primarily due to:
an increase in transmission construction expenditures primarily due to a higher scope of work done in 2015;
an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and
money pool activityactivity.
The increase was partially offset by $12.9 million of insurance proceeds received in 2015 related to the Baxter Wilson Plant Event. See “Baxter Wilson Plant Event” above for a discussion ofunplanned outage event that occurred at the Baxter Wilson (Unit 1) power plant event.in September 2013.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $25.3 million in 2015 compared to increasing by $0.6 million in 2014. 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 $28.4 million in 2014 primarily due to money pool activity and an increase in fossil-fueled generation construction expenditures primarily due to a higher scope of work done
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
during plant outages in 2014 and an increase in spending on Baxter Wilson (Unit 1) repairs in 2014. The increase was partially offset by a decrease in transmission construction expenditures as a result of a decrease in reliability work performed in 2014.
Increases in Entergy Mississippi’s receivable from the money pool are a use of cash flow, and Entergy Mississippi’s receivable from the money pool increased by $0.6 million in 2014 compared to decreasing by $16.9 million in 2013.
Financing Activities
Entergy Mississippi’s financing activities provided $8.4 million of cash in 2016 compared to using $43.2 million in 2015 primarily due to the net issuance of $61.4 million of long-term debt in 2016 and a decrease of $16 million in common stock dividends paid in 2016, partially offset by the redemption of $30 million of 6.25% Series preferred stock. The decrease in dividends paid was primarily because of lower operating cash flows and higher capital expenditures, each discussed above.
Net cash flow used in financing activities decreased $20.9 million in 2015 primarily due to a decrease of $21.4 million in common stock dividends paid.
Net cash flow used The decrease in financing activities decreased $59.1 million in 2014dividends paid was primarily due to the issuance of $100 million of 3.75% Series first mortgage bonds in March 2014 and the payment, at maturity, of $100 million of 5.15% Series first mortgage bonds in February 2013.
The decrease was partially offset by:
the payment, prior to maturity, of $95 million of 4.95% Series first mortgage bonds in April 2014;
an increase of $54 million in common stock dividends paid; and
money pool activity.
Decreases in Entergy Mississippi’s payable to the money pool are a use of cash flow, and Entergy Mississippi’s payable to the money pool decreased by $3.5 million in 2014 compared to increasing by $3.5 million in 2013.higher capital expenditures, as discussed above.
See Note 5 to the financial statements for details on long-term debt.
Capital Structure
Entergy Mississippi’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio is due to an increase in retained earnings.
| | | | December 31,
2015 | | December 31,
2014 | December 31,
2016 | | December 31,
2015 |
| Debt to capital | 49.7 | % | | 51.2 | % | 50.2 | % | | 49.7 | % |
| Effect of subtracting cash | (3.8 | %) | | (1.5 | %) | (1.8 | %) | | (3.8 | %) |
| Net debt to net capital | 45.9 | % | | 49.7 | % | 48.4 | % | | 45.9 | % |
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, capital lease obligations, and long-term debt, including the currently maturing portion. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Mississippi uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Mississippi’s financial condition. 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’s financial condition because net debt indicates Entergy Mississippi’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Mississippi Inc.seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Mississippi may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Mississippi may receive equity contributions to maintain the targeted capital structure.
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 or retirements;
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
working capital purposes, including the financing of fuel and purchased power costs; and
dividend and interest payments.
Following are the amounts of Entergy Mississippi’s planned construction and other capital investments.
| | | | 2016 | | 2017 | | 2018 | 2017 | | 2018 | | 2019 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $35 |
| |
| $40 |
| |
| $50 |
|
| $45 |
| |
| $50 |
| |
| $40 |
|
| Transmission | 135 |
| | 145 |
| | 85 |
| 170 |
| | 135 |
| | 85 |
|
| Distribution | 130 |
| | 110 |
| | 120 |
| 135 |
| | 115 |
| | 130 |
|
| Other | 20 |
| | 20 |
| | 10 |
| 60 |
| | 40 |
| | 25 |
|
| Total |
| $320 |
| |
| $315 |
| |
| $265 |
|
| $410 |
| |
| $340 |
| |
| $280 |
|
Following are the amounts of Entergy Mississippi’s existing debt obligations and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total | 2017 | | 2018-2019 | | 2020-2021 | | After 2021 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $174 |
| |
| $95 |
| |
| $231 |
| |
| $1,324 |
| |
| $1,824 |
|
| $45 |
| |
| $235 |
| |
| $70 |
| |
| $1,644 |
| |
| $1,994 |
|
| Capital lease payments |
| $2 |
| |
| $2 |
| |
| $— |
| |
| $— |
| |
| $4 |
|
| $2 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $2 |
|
| Operating leases |
| $7 |
| |
| $11 |
| |
| $8 |
| |
| $6 |
| |
| $32 |
|
| $8 |
| |
| $14 |
| |
| $10 |
| |
| $6 |
| |
| $38 |
|
| Purchase obligations (b) |
| $267 |
| |
| $491 |
| |
| $467 |
| |
| $780 |
| |
| $2,005 |
|
| $240 |
| |
| $440 |
| |
| $421 |
| |
| $4,762 |
| |
| $5,863 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | 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 $19.9$19.1 million to its qualified pension plans and approximately $140 thousand to other postretirement health care and life insurance plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017 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 Mississippi has $18.5$9.8 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.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Mississippi includes amounts associated with specific investments such as transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintainenhance reliability and improve service to customers, including initial investment to support smart meter deployment;advanced metering; resource planning, including
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
potential generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, 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 Notes 5 and 6 to the financial statements.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
As a wholly-owned subsidiary, Entergy Mississippi dividends its earnings to Entergy Corporation at a percentage determined monthly. Provisions in Entergy Mississippi’s long-term debt indenture restrictsarticles of incorporation relating to preferred stock restrict 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, 2015, Entergy Mississippi had restricted retained earnings unavailable for distribution to Entergy Corporation of $68.5 million.
New Nuclear Generation Development Costs
Pursuant to the Mississippi Baseload Act and the Mississippi Public Utilities Act, Entergy Mississippi had been developing and preserving a project option for new nuclear generation at Grand Gulf Nuclear Station. In October 2010, Entergy Mississippi filed an application with the MPSC requesting that the MPSC determine that it was 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 stated that there should be a deferral of the $57 million of costs incurred through September 2011 in connection with planning, evaluating, monitoring, and other related generation resource development activities for new nuclear generation at Grand Gulf.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations in Entergy Mississippi’s general rate case proceeding, which are discussed below. In consideration of the comprehensive terms for settlement in that rate case proceeding, the Mississippi Public Utilities Staff and Entergy Mississippi agreed that Entergy Mississippi would request consolidation of the new nuclear generation development costs proceeding with the rate case proceeding for hearing purposes and will not further pursue, except as noted below, recovery of the costs deferred by MPSC order in the new nuclear generation development docket. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. After considering the progress of the new nuclear generation costs proceeding in light of the joint stipulation, Entergy Mississippi recorded in 2014 a $56.2 million pre-tax charge to recognize that the regulatory asset associated with new nuclear generation development is no longer probable of recovery. In December 2014 the MPSC issued an order accepting in their entirety the October 2014 stipulations, including the findings and terms of the stipulations regarding new nuclear generation development costs.
Sources of Capital
Entergy Mississippi’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Mississippi may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
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.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Entergy Mississippi’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| $25,930 | | $644 | | ($3,536) | | $16,878 |
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| $10,595 | | $25,930 | | $644 | | ($3,536) |
See Note 4 to the financial statements for a description of the money pool.
Entergy Mississippi has four separate credit facilities in the aggregate amount of $102.5 million scheduled to expire May 2016.2017. No borrowings were outstanding under the credit facilities as of December 31, 2015.2016. In addition, Entergy Mississippi is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2015,2016, a $6$7.1 million letter of credit was outstanding under Entergy Mississippi’s uncommitted letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Mississippi obtained authorizations from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $175 million at any time outstanding and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Mississippi’s short-term borrowing limits.
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 March 2013, Entergy Mississippi submitted its formula rate plan filing for the 2012 test year. The filing requested a $36.3 million revenue increase to reset Entergy Mississippi’s return on common equity to 10.55%, which is a point within the formula rate plan bandwidth. In June 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, in which both parties agreed that the MPSC should approve a $22.3 million rate increase for Entergy Mississippi which, with other adjustments reflected in the stipulation, would have the effect of resetting Entergy Mississippi’s return on common equity to 10.59% when adjusted for performance under the formula rate plan. In August 2013 the MPSC approved the joint stipulation between Entergy Mississippi and the Mississippi Public Utilities Staff authorizing the rate increase effective with September 2013 bills. Additionally, the MPSC authorized Entergy Mississippi to defer approximately $1.2 million in MISO-related implementation costs incurred in 2012 along with other MISO-related implementation costs incurred in 2013.
In June 2014, Entergy Mississippi filed its first general rate case before the MPSC in almost 12 years. The rate filing laid out Entergy Mississippi’s plans for improving reliability, modernizing the grid, maintaining its workforce, stabilizing rates, utilizing new technologies, and attracting new industry to its service territory. Entergy Mississippi requested a net increase in revenue of $49 million for bills rendered during calendar year 2015, including $30 million resulting from new depreciation rates to update the estimated service life of assets. In addition, the filing proposed, among other things: 1) realigning cost recovery of the Attala and Hinds power plant acquisitions from the power
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
management rider to base rates; 2) including certain MISO-related revenues and expenses in the power management rider; 3) power management rider changes that reflect the changes in costs and revenues that will accompany Entergy Mississippi’s withdrawal from participation in the System Agreement; and 4) a formula rate plan forward test year to allow for known changes in expenses and revenues for the rate effective period. Entergy Mississippi proposed maintaining the current authorized return on common equity of 10.59%.
In October 2014, Entergy Mississippi and the Mississippi Public Utilities Staff entered into and filed joint stipulations that addressed the majority of issues in the proceeding. The stipulations provided for:
an approximate $16 million net increase in revenues, which reflected an agreed upon 10.07% return on common equity;
revision of Entergy Mississippi’s formula rate plan by providing Entergy Mississippi with the ability to reflect known and measurable changes to historical rate base and certain expense amounts; resolving uncertainty around and obviating the need for an additional rate filing in connection with Entergy Mississippi’s withdrawal from participation in the System Agreement; updating depreciation rates; and moving costs associated with the Attala and Hinds generating plants from the power management rider to base rates;
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
recovery of non-fuel MISO-related costs through a separate rider for that purpose;
a deferral of $6 million in other operation and maintenance expenses associated with the unplanned Baxter Wilson outage in September 2013, and a determination that the regulatory asset should accrue carrying costs, with amortization of the regulatory asset over two years beginning in February 2015, and a provision that the capital costs will be reflected in rate base. See “Baxter Wilson Plant Event” above for further discussionThe final accounting of costs to return the unit to service and insurance proceeds were to be addressed in Entergy Mississippi’s next formula rate plan filing. Subsequently, the MPSC ordered final review of the Baxter Wilson outage;accounting be completed in a separate docket; and
consolidation of the new nuclear generation development costs proceeding with the general rate case proceeding for hearing purposes and a determination that Entergy Mississippi would not further pursue, except as noted below, recovery of the costs that were approved for deferral by the MPSC in November 2011. The stipulations state, however, that, if Entergy Mississippi decides to move forward with nuclear development in Mississippi, it can at that time re-present for consideration by the MPSC only those costs directly associated with the existing early site permit (ESP), to the extent that the costs are verifiable and prudent and the ESP is still valid and relevant to any such option pursued. See “New Nuclear Generation Development Costs” above for further discussion of the new nuclear generation development costs proceeding and subsequent write-off in 2014 of the regulatory asset related to those costs.
In December 2014 the MPSC issued an order accepting the stipulations in their entirety and approving the revenue adjustments and rate changes effective with February 2015 bills.
In March 2016, Entergy Mississippi submitted its formula rate plan 2016 test year filing showing Entergy Mississippi’s projected earned return for the 2016 calendar year to be below the formula rate plan bandwidth. The filing showed a $32.6 million rate increase was necessary to reset Entergy Mississippi’s earned return on common equity to the specified point of adjustment of 9.96%, within the formula rate plan bandwidth. In June 2016 the MPSC approved Entergy Mississippi’s joint stipulation with the Mississippi Public Utilities Staff. The joint stipulation provided for a total revenue increase of $23.7 million. The revenue increase includes a $19.4 million increase through the formula rate plan, resulting in a return on common equity point of adjustment of 10.07%. The revenue increase also includes $4.3 million in incremental ad valorem tax expenses to be collected through an updated ad valorem tax adjustment rider. The revenue increase and ad valorem tax adjustment rider were effective with the July 2016 bills.
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 iswas still appropriate or cancould be improved to better serve the public interest. The intent of this inquiry and review was 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. In March 2013 the Mississippi Public Utilities Staff filed its consultant’s report which noted the return on common equity estimation methods used by Entergy Mississippi and Mississippi Power Company are commonly used throughout the electric utility industry. The report suggested ways in which the methods used by Entergy Mississippi and Mississippi Power Company might be improved, but did not recommend specific changes in the return on common equity formulas or calculations at that time. In June 2014 the MPSC expanded the scope of the August 2012 inquiry to study the merits of adopting a uniform formula rate plan that could be applied, where possible in whole or in part, to both Entergy Mississippi and Mississippi Power Company in order to achieve greater consistency in the plans. The MPSC directed the Mississippi Public Utilities Staff to investigate and review Entergy Mississippi’s formula rate plan rider schedule and Mississippi Power Company’s Performance Evaluation Plan by considering the merits and deficiencies and possibilities for improvement of each and then to propose a uniform formula rate plan that, where possible, could be applicable to both companies. No procedural schedule has been set. In October 2014 the Mississippi Public Utilities Staff conducted a public technical conference to discuss performance benchmarking and its potential application to the electric utilities’ formula rate plans.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
In Entergy Mississippi’s 2014 general rate case, the Mississippi Public Utilities Staff conducted a review of Entergy Mississippi’s proposed changes to its formula rate plan and recommended changes in that proceeding that may be duplicative of the review being conducted simultaneously in the above-described formula rate plan docket. Consequently, the MPSC found in the general rate case order that the changes to Entergy Mississippi’s formula rate plan schedule approved in that order are just and reasonable and should remain unchanged by any MPSC action in the above-described formula rate plan docket, but that any provisions of Entergy Mississippi’s formula rate plan schedule not specifically addressed in the general rate case order may be reviewed and changed.
Fuel and Purchased Power Cost Recovery
Entergy Mississippi’s rate schedules include an energy cost recovery rider that 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.
Entergy Mississippi had a deferred fuel balance of $60.4 million as of March 31, 2014. In May 2014, Entergy Mississippi filed for an interim adjustment under its energy cost recovery rider. The interim adjustment proposed a net energy cost factor designed to collect over a six-month period the under-recovered deferred fuel balance as of March 31, 2014 and also reflected a natural gas price of $4.50 per MMBtu. In May 2014, Entergy Mississippi and the Public Utilities Staff entered into a joint stipulation in which Entergy Mississippi agreed to a revised net energy cost factor that reflected the proposed interim adjustment with a reduction in costs recovered through the energy cost recovery rider associated with the suspension of the DOE nuclear waste storage fee. In June 2014 the MPSC approved the joint stipulation and allowed Entergy Mississippi’s interim adjustment. In November 2014, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. Due to lower gas prices and a lower deferred fuel balance, the redetermined annual factor was a decrease from the revised interim net energy cost factor. In January 2015 the MPSC approved the redetermined annual factor effective January 30, 2015.
Entergy Mississippi had a deferred fuel over-recovery balance of $58.3 million as of May 31, 2015, along with an under-recovery balance of $12.3 million under the power management rider. Pursuant to those tariffs, in July 2015, Entergy Mississippi filed for interim adjustments under both the energy cost recovery rider and the power management rider to flow through to customers the approximately $46 million net over-recovery over a six-month period. In August 2015, the MPSC approved the interim adjustments effective with September 2015 bills. In November 2015, Entergy Mississippi filed its annual redetermination of the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included a projected over-recovery balance of $48 million projected through January 31, 2016. In January 2016 the MPSC approved the redetermined annual factor effective February 1, 2016. The MPSC further ordered, however, that due to the significant change in natural gas price forecasts since Entergy Mississippi’s filing in November 2015 Entergy Mississippi shall file a revised fuel factor with the MPSC no later than February 1, 2016. In February 2016,Pursuant to that order, Entergy Mississippi submitted a revised fuel factor. Additionally, because Entergy Mississippi’s projected over-recovery balance for the period ending January 31, 2016 was $68 million, in February 2016, Entergy Mississippi filed for another interim adjustment to the energy cost factor reflectingeffective April 2016 to flow through to customers the projected over-recovery balance over a natural gas pricesix-month period. That interim adjustment was approved by the MPSC in February 2016 effective for April 2016 bills.
In November 2016, Entergy Mississippi filed its annual redetermination of $2.45 per MMBtu.the annual factor to be applied under the energy cost recovery rider. The calculation of the annual factor included an over-recovery of less than $2 million as of September 30, 2016. In January 2017 the MPSC approved the annual factor effective with February 2017 bills. Also in January 2017 the MPSC certified to the Mississippi Legislature the audit reports of its independent auditors for the fuel year ending September 30, 2016. In its order, the MPSC expressly reserved the right to review and determine the recoverability of any and all purchased power expenditures made during fiscal year 2016.
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 lawsuit 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.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
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.
In January 2014 the U.S. Supreme Court issued a decision in which it held that cases brought by attorneys general as the sole plaintiff to enforce state laws were not considered “mass actions” under the Class Action Fairness Act, so as to establish federal subject matter jurisdiction. One day later the Attorney General renewed his motion to remand the Entergy case back to state court, citing the U.S. Supreme Court’s decision. The defendant Entergy companies responded to that motion reiterating the additional grounds asserted for federal question jurisdiction, and the District Court held oral argument on the renewed motion to remand in February 2014. In April 2015 the District Court entered an order denying the renewed motion to remand, holding that the District Court has federal question subject matter jurisdiction. The Attorney General appealed to the U.S. Fifth Circuit Court of Appeals the denial of the motion to remand. In July 2015 the Fifth Circuit issued an order denying the appeal, and the Attorney General subsequently filed a petition for rehearing of the request for interlocutory appeal, which was also denied. The case remains pending in federal district court, awaiting a ruling on the Entergy companies’ motion for judgment on the pleadings. In December 2015 the District Court ordered that the parties submit to the court undisputed and disputed facts that are material to the Entergy defendants’ motion for judgment on the pleadings, as well as supplemental briefs regarding the same. Those filings were made in January 2016.
In September 2016 the Attorney General filed a mandamus petition with the U.S. Fifth Circuit Court of Appeals in which the Attorney General asked the Fifth Circuit to order the chief judge to reassign this case to another judge. In September 2016 the District Court denied the Entergy companies’ motion for judgment on the pleadings. The Entergy companies filed a motion seeking to amend the District Court’s order denying the Entergy companies’ motion for judgment on the pleadings and allowing an interlocutory appeal. In October 2016 the Fifth Circuit granted the Attorney General’s motion for writ of mandamus and directed the chief judge to assign the case to a new judge. The case was reassigned in October 2016. In January 2017 the District Court denied the Entergy companies’ motion to amend the order denying the motion for judgment on the pleadings, and the parties are in the process of preparing a proposed case management order.
Advanced Metering Infrastructure (AMI) Filing
In November 2016, Entergy Mississippi filed an application seeking an order from the MPSC granting a certificate of public convenience and necessity and finding that Entergy Mississippi’s deployment of AMI is in the public interest. Entergy Mississippi proposed to replace existing meters with advanced meters that enable two-way data communication; to design and build a secure and reliable network to support such communications; and to implement support systems. AMI is intended to serve as the foundation of Entergy Mississippi’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy Mississippi provided a cost benefit analysis showing that its AMI deployment is expected to produce a nominal benefit to customers of $496 million over a 15 year period, which when netted against the costs of AMI results in $183 million of net customer benefits. Entergy Mississippi also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $56 million, of existing meters that will be retired as part of the AMI deployment and also to depreciate those assets using current depreciation rates. Entergy Mississippi proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019, subject to approval by the MPSC, with deployment of the communications network expected to begin in 2018. Entergy Mississippi proposed to include the AMI deployment costs and the quantified benefits in existing rate mechanisms, primarily through future formula rate plan filings and/or future energy cost recovery rider schedule re-determinations, as applicable.
Storm Damage AccrualProvision and Storm Cost Recovery
On July 1, 2013, Entergy Mississippi and the Mississippi Public Utilities Staff entered into a joint stipulation, wherein both parties agreed that approximately $32 million in storm restoration costs incurred in 2011 and 2012 were
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
prudently incurred and chargeable to the storm damage provision, while approximately $700,000 in prudently incurred costs were more properly recoverable through the formula rate plan. Entergy Mississippi and the Mississippi Public Utilities Staff also agreed that the storm damage accrualprovision should be increased from $750,000 per month to $1.75 million per month. In September 2013 the MPSC approved the joint stipulation with the increase in the storm damage accrualprovision effective with October 2013 bills. In February 2015, Entergy Mississippi provided notice to the Mississippi Public Utilities Staff that the storm damage accrualprovision would be set to zero effective with the March 2015 billing cycle as a result of Entergy Mississippi’s storm damage accrualprovision balance exceeding $15 million as of January 31, 2015, but willwould return to its current level when the storm damage accrualprovision balance becomes less than $10 million. As of April 30, 2016, Entergy Mississippi’s storm damage provision balance was less than $10 million, therefore Entergy Mississippi resumed billing the monthly storm damage provision effective with June 2016 bills. As of September 30, 2016, however, Entergy Mississippi’s storm damage provision balance again exceeded $15 million. Accordingly the storm damage provision was reset to zero beginning with the November 2016 billing cycle and will remain at zero until the balance again becomes less than $10 million, at which time it will return to its prior level.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization” and “System Agreement” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Environmental Risks
Entergy Mississippi’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 Mississippi 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 Mississippi, Inc.
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy Mississippi’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’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy Mississippi records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Taxation and a receivable,Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of the unbilled receivable at the beginning of the periodEntergy Corporation 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 periodSubsidiaries Management’s Financial Discussion 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.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Mississippi’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in 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 2015 Qualified Pension Cost | | Impact on 2015 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,213 | | $12,607 | | (0.25%) | | $901 | |
| $12,896 |
|
| Rate of return on plan assets | | (0.25%) | | $740 | | $— | | (0.25%) | | $818 | | $- |
|
| Rate of increase in compensation | | 0.25% | | $438 | | $1,887 | | 0.25% | | $409 | |
| $2,519 |
|
Entergy Mississippi, Inc.
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 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $219 | | $2,547 | | (0.25%) | | $195 | | $2,334 |
| Health care cost trend | | 0.25% | | $386 | | $2,354 | | 0.25% | | $343 | | $1,909 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy Mississippi, Inc.
Management’s Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for Entergy Mississippi in 20152016 was $16.4$9.5 million. Entergy Mississippi anticipates 20162017 qualified pension cost to be $9.5$8.5 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.8 million. Entergy Mississippi contributed $22.5$20 million to its qualified pension plans in 20152016 and estimates 2016-20182017 pension contributions will approximate $54be approximately $19.1 million, including $19.9 million in 2016, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total postretirement health care and life insurance benefit income for Entergy Mississippi in 20152016 was $758 thousand.$1.2 million. Entergy Mississippi expects 20162017 postretirement health care and life insurance benefit income of approximately $1.2$1 million. In 2016, Entergy Mississippi refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $770 thousand. Entergy Mississippi contributed $661$685 thousand to its other postretirement plans in 20152016 and expects 2016-2018estimates that 2017 contributions to approximate $419 thousand, includingwill be approximately $140 thousand in 2016.thousand.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $33.5 million in the qualified pension benefit obligation and $4.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.8 million and other postretirement cost by approximately $0.6 million. Pension funding guidelines, as established byIn 2016, the Employee Retirement Income Security Act of 1974, as amended andmortality projection scale was updated to MP-2016, with no change in the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries newbase mortality assumptions until after 2015, possibly 2016.table assumption.
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.
Other Contingencies
Entergy Mississippi, Inc.
Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
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, 20152016 and 2014,2015, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 378376 through 382380 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 20152016 and 2014,2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,094,649 |
| |
| $1,396,985 |
| |
| $1,524,193 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 95,090 |
| | 291,666 |
| | 325,643 |
|
| Purchased power | | 297,902 |
| | 389,950 |
| | 493,533 |
|
| Other operation and maintenance | | 250,443 |
| | 261,255 |
| | 256,339 |
|
| Asset write-off | | — |
| | — |
| | 56,225 |
|
| Taxes other than income taxes | | 94,482 |
| | 94,152 |
| | 87,936 |
|
| Depreciation and amortization | | 136,214 |
| | 129,029 |
| | 113,903 |
|
| Other regulatory charges (credits) - net | | (3,721 | ) | | 19,027 |
| | 3,854 |
|
| TOTAL | | 870,410 |
| | 1,185,079 |
| | 1,337,433 |
|
| | | | | | | |
| OPERATING INCOME | | 224,239 |
| | 211,906 |
| | 186,760 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 5,801 |
| | 3,095 |
| | 2,380 |
|
| Interest and investment income | | 656 |
| | 195 |
| | 1,055 |
|
| Miscellaneous - net | | (3,531 | ) | | (4,418 | ) | | (3,905 | ) |
| TOTAL | | 2,926 |
| | (1,128 | ) | | (470 | ) |
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 57,114 |
| | 57,842 |
| | 57,002 |
|
| Allowance for borrowed funds used during construction | | (2,987 | ) | | (1,644 | ) | | (1,243 | ) |
| TOTAL | | 54,127 |
| | 56,198 |
| | 55,759 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 173,038 |
| | 154,580 |
| | 130,531 |
|
| | | | | | | |
| Income taxes | | 63,854 |
| | 61,872 |
| | 55,710 |
|
| | | | | | | |
| NET INCOME | | 109,184 |
| | 92,708 |
| | 74,821 |
|
| | | | | | | |
| Preferred dividend requirements and other | | 2,443 |
| | 2,828 |
| | 2,828 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $106,741 |
| |
| $89,880 |
| |
| $71,993 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $109,184 |
| |
| $92,708 |
| |
| $74,821 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 136,214 |
| | 129,029 |
| | 113,903 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 60,986 |
| | 18,673 |
| | 32,472 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (28,819 | ) | | 50,199 |
| | (27,444 | ) |
| Fuel inventory | | 401 |
| | (8,537 | ) | | 6,163 |
|
| Accounts payable | | 33,733 |
| | (26,682 | ) | | (14,618 | ) |
| Taxes accrued | | 20,579 |
| | (10,104 | ) | | 318 |
|
| Interest accrued | | 822 |
| | (2,341 | ) | | 2,789 |
|
| Deferred fuel costs | | (114,711 | ) | | 105,560 |
| | 40,251 |
|
| Other working capital accounts | | (5,222 | ) | | (663 | ) | | 17,567 |
|
| Provisions for estimated losses | | 6,378 |
| | (2,080 | ) | | 14,468 |
|
| Other regulatory assets | | (3,626 | ) | | 39,582 |
| | (36,875 | ) |
| Pension and other postretirement liabilities | | (10,648 | ) | | (14,939 | ) | | 68,434 |
|
| Other assets and liabilities | | 7,009 |
| | 1,874 |
| | 11,214 |
|
| Net cash flow provided by operating activities | | 212,280 |
| | 372,279 |
| | 303,463 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (310,356 | ) | | (235,894 | ) | | (179,544 | ) |
| Allowance for equity funds used during construction | | 5,801 |
| | 3,095 |
| | 2,380 |
|
| Insurance proceeds | | — |
| | 12,932 |
| | — |
|
| Changes in money pool receivable - net | | 15,335 |
| | (25,286 | ) | | (644 | ) |
| Other | | (224 | ) | | 26 |
| | 43 |
|
| Net cash flow used in investing activities | | (289,444 | ) | | (245,127 | ) | | (177,765 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 623,812 |
| | — |
| | 98,668 |
|
| Retirement of long-term debt | | (562,400 | ) | | — |
| | (95,000 | ) |
| Changes in money pool payable - net | | — |
| | — |
| | (3,536 | ) |
| Redemption of preferred stock | | (30,000 | ) | | — |
| | — |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (24,000 | ) | | (40,000 | ) | | (61,400 | ) |
| Preferred stock | | (2,755 | ) | | (2,828 | ) | | (2,828 | ) |
| Other | | 3,736 |
| | (352 | ) | | — |
|
| Net cash flow provided by (used in) financing activities | | 8,393 |
| | (43,180 | ) | | (64,096 | ) |
| Net increase (decrease) in cash and cash equivalents | | (68,771 | ) | | 83,972 |
| | 61,602 |
|
| Cash and cash equivalents at beginning of period | | 145,605 |
| | 61,633 |
| | 31 |
|
| Cash and cash equivalents at end of period | |
| $76,834 |
| |
| $145,605 |
| |
| $61,633 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $53,693 |
| |
| $57,576 |
| |
| $51,509 |
|
| Income taxes | |
| ($12,487 | ) | |
| $61,333 |
| |
| $19,650 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $16 |
| |
| $1,426 |
|
| Temporary cash investments | | 76,818 |
| | 144,179 |
|
| Total cash and cash equivalents | | 76,834 |
| | 145,605 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 51,218 |
| | 56,685 |
|
| Allowance for doubtful accounts | | (549 | ) | | (718 | ) |
| Associated companies | | 45,973 |
| | 34,964 |
|
| Other | | 12,006 |
| | 8,276 |
|
| Accrued unbilled revenues | | 51,327 |
| | 47,284 |
|
| Total accounts receivable | | 159,975 |
| | 146,491 |
|
| Deferred fuel costs | | 6,957 |
| | — |
|
| Fuel inventory - at average cost | | 50,872 |
| | 51,273 |
|
| Materials and supplies - at average cost | | 41,146 |
| | 39,491 |
|
| Prepayments and other | | 8,873 |
| | 5,184 |
|
| TOTAL | | 344,657 |
| | 388,044 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,608 |
| | 4,625 |
|
| Escrow accounts | | 31,783 |
| | 41,726 |
|
| TOTAL | | 36,391 |
| | 46,351 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 4,321,214 |
| | 4,083,933 |
|
| Property under capital lease | | 1,590 |
| | 2,942 |
|
| Construction work in progress | | 118,182 |
| | 114,067 |
|
| TOTAL UTILITY PLANT | | 4,440,986 |
| | 4,200,942 |
|
| Less - accumulated depreciation and amortization | | 1,602,711 |
| | 1,534,522 |
|
| UTILITY PLANT - NET | | 2,838,275 |
| | 2,666,420 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | 38,284 |
| | 45,790 |
|
| Other regulatory assets | | 342,213 |
| | 328,681 |
|
| Other | | 2,320 |
| | 2,121 |
|
| TOTAL | | 382,817 |
| | 376,592 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,602,140 |
| |
| $3,477,407 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $125,000 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 43,647 |
| | 38,496 |
|
| Other | | 80,227 |
| | 51,502 |
|
| Customer deposits | | 84,112 |
| | 81,583 |
|
| Taxes accrued | | 64,040 |
| | 43,461 |
|
| Interest accrued | | 21,653 |
| | 20,831 |
|
| Deferred fuel costs | | — |
| | 107,754 |
|
| Other | | 9,554 |
| | 22,754 |
|
| TOTAL | | 303,233 |
| | 491,381 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 861,331 |
| | 810,635 |
|
| Accumulated deferred investment tax credits | | 8,667 |
| | 4,645 |
|
| Asset retirement cost liabilities | | 8,722 |
| | 8,252 |
|
| Accumulated provisions | | 54,440 |
| | 48,062 |
|
| Pension and other postretirement liabilities | | 109,551 |
| | 120,217 |
|
| Long-term debt | | 1,120,916 |
| | 920,085 |
|
| Other | | 20,108 |
| | 11,699 |
|
| TOTAL | | 2,183,735 |
| | 1,923,595 |
|
| | | | | |
| Commitments and Contingencies | |
|
| |
|
|
| | | | | |
| Preferred stock without sinking fund | | 20,381 |
| | 50,381 |
|
| | | | | |
| COMMON EQUITY | | |
| | |
|
| Common stock, no par value, authorized 12,000,000 shares; issued and outstanding 8,666,357 shares in 2016 and 2015 | | 199,326 |
| | 199,326 |
|
| Capital stock expense and other | | 167 |
| | (690 | ) |
| Retained earnings | | 895,298 |
| | 813,414 |
|
| TOTAL | | 1,094,791 |
| | 1,012,050 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,602,140 |
| |
| $3,477,407 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Capital Stock Expense and Other | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2013 |
| $199,326 |
| |
| ($690 | ) | |
| $752,941 |
| |
| $951,577 |
|
| Net income | — |
| | — |
| | 74,821 |
| | 74,821 |
|
| Common stock dividends | — |
| | — |
| | (61,400 | ) | | (61,400 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2014 |
| $199,326 |
| |
| ($690 | ) | |
| $763,534 |
| |
| $962,170 |
|
| Net income | — |
| | — |
| | 92,708 |
| | 92,708 |
|
| Common stock dividends | — |
| | — |
| | (40,000 | ) | | (40,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2015 |
| $199,326 |
| |
| ($690 | ) | |
| $813,414 |
| |
| $1,012,050 |
|
| Net income | — |
| | — |
| | 109,184 |
| | 109,184 |
|
| Common stock dividends | — |
| | — |
| | (24,000 | ) | | (24,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,443 | ) | | (2,443 | ) |
| Preferred stock redemption | — |
| | 857 |
| | (857 | ) | | — |
|
| Balance at December 31, 2016 |
| $199,326 |
| |
| $167 |
| |
| $895,298 |
| |
| $1,094,791 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,094,649 |
| |
| $1,396,985 |
| |
| $1,524,193 |
| |
| $1,334,540 |
| |
| $1,120,366 |
|
| Net income |
| $109,184 |
| |
| $92,708 |
| |
| $74,821 |
| |
| $82,159 |
| |
| $46,768 |
|
| Total assets |
| $3,602,140 |
| |
| $3,477,407 |
| |
| $3,358,625 |
| |
| $3,234,875 |
| |
| $3,337,230 |
|
| Long-term obligations (a) |
| $1,141,924 |
| |
| $972,058 |
| |
| $1,097,182 |
| |
| $1,092,786 |
| |
| $1,108,432 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $459 |
| |
| $565 |
| |
| $585 |
| |
| $527 |
| |
| $454 |
|
| Commercial | 374 |
| | 465 |
| | 481 |
| | 432 |
| | 381 |
|
| Industrial | 134 |
| | 164 |
| | 175 |
| | 156 |
| | 140 |
|
| Governmental | 38 |
| | 47 |
| | 47 |
| | 42 |
| | 37 |
|
| Total retail | 1,005 |
| | 1,241 |
| | 1,288 |
| | 1,157 |
| | 1,012 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1 |
| | 75 |
| | 153 |
| | 92 |
| | 23 |
|
| Non-associated companies | 30 |
| | 10 |
| | 14 |
| | 24 |
| | 24 |
|
| Other | 59 |
| | 71 |
| | 69 |
| | 62 |
| | 61 |
|
| Total |
| $1,095 |
| |
| $1,397 |
| |
| $1,524 |
| |
| $1,335 |
| |
| $1,120 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,617 |
| | 5,661 |
| | 5,672 |
| | 5,629 |
| | 5,550 |
|
| Commercial | 4,894 |
| | 4,913 |
| | 4,821 |
| | 4,815 |
| | 4,915 |
|
| Industrial | 2,493 |
| | 2,283 |
| | 2,297 |
| | 2,265 |
| | 2,400 |
|
| Governmental | 439 |
| | 433 |
| | 414 |
| | 409 |
| | 408 |
|
| Total retail | 13,443 |
| | 13,290 |
| | 13,204 |
| | 13,118 |
| | 13,273 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | — |
| | 1,419 |
| | 2,657 |
| | 1,543 |
| | 232 |
|
| Non-associated companies | 1,021 |
| | 261 |
| | 193 |
| | 304 |
| | 265 |
|
| Total | 14,464 |
| | 14,970 |
| | 16,054 |
| | 14,965 |
| | 13,770 |
|
(Page left blank intentionally)
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $1,396,985 |
| |
| $1,524,193 |
| |
| $1,334,540 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 291,666 |
| | 325,643 |
| | 328,934 |
|
| Purchased power | | 389,950 |
| | 493,533 |
| | 375,745 |
|
| Other operation and maintenance | | 261,255 |
| | 256,339 |
| | 261,832 |
|
| Asset write-off | | — |
| | 56,225 |
| | — |
|
| Taxes other than income taxes | | 94,152 |
| | 87,936 |
| | 83,630 |
|
| Depreciation and amortization | | 129,029 |
| | 113,903 |
| | 108,714 |
|
| Other regulatory charges (credits) - net | | 19,027 |
| | 3,854 |
| | (14,545 | ) |
| TOTAL | | 1,185,079 |
| | 1,337,433 |
| | 1,144,310 |
|
| | | | | | | |
| OPERATING INCOME | | 211,906 |
| | 186,760 |
| | 190,230 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 3,095 |
| | 2,380 |
| | 2,182 |
|
| Interest and investment income | | 195 |
| | 1,055 |
| | 817 |
|
| Miscellaneous - net | | (4,418 | ) | | (3,905 | ) | | (3,821 | ) |
| TOTAL | | (1,128 | ) | | (470 | ) | | (822 | ) |
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 57,842 |
| | 57,002 |
| | 59,031 |
|
| Allowance for borrowed funds used during construction | | (1,644 | ) | | (1,243 | ) | | (1,539 | ) |
| TOTAL | | 56,198 |
| | 55,759 |
| | 57,492 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 154,580 |
| | 130,531 |
| | 131,916 |
|
| | | | | | | |
| Income taxes | | 61,872 |
| | 55,710 |
| | 49,757 |
|
| | | | | | | |
| NET INCOME | | 92,708 |
| | 74,821 |
| | 82,159 |
|
| | | | | | | |
| Preferred dividend requirements and other | | 2,828 |
| | 2,828 |
| | 2,828 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $89,880 |
| |
| $71,993 |
| |
| $79,331 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $92,708 |
| |
| $74,821 |
| |
| $82,159 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 129,029 |
| | 113,903 |
| | 108,714 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 18,673 |
| | 32,472 |
| | 47,878 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | 50,199 |
| | (27,444 | ) | | (31,647 | ) |
| Fuel inventory | | (8,537 | ) | | 6,163 |
| | (121 | ) |
| Accounts payable | | (26,682 | ) | | (14,618 | ) | | 38,727 |
|
| Taxes accrued | | (10,104 | ) | | 318 |
| | 920 |
|
| Interest accrued | | (2,341 | ) | | 2,789 |
| | 2,157 |
|
| Deferred fuel costs | | 105,560 |
| | 40,251 |
| | (11,567 | ) |
| Other working capital accounts | | (663 | ) | | 17,567 |
| | (12,820 | ) |
| Provisions for estimated losses | | (2,080 | ) | | 14,468 |
| | (146 | ) |
| Other regulatory assets | | 39,582 |
| | (36,875 | ) | | 87,907 |
|
| Pension and other postretirement liabilities | | (14,939 | ) | | 68,434 |
| | (94,143 | ) |
| Other assets and liabilities | | 1,874 |
| | 11,214 |
| | 1,647 |
|
| Net cash flow provided by operating activities | | 372,279 |
| | 303,463 |
| | 219,665 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (235,894 | ) | | (179,544 | ) | | (168,510 | ) |
| Allowance for equity funds used during construction | | 3,095 |
| | 2,380 |
| | 2,182 |
|
| Insurance proceeds | | 12,932 |
| | — |
| | — |
|
| Changes in money pool receivable - net | | (25,286 | ) | | (644 | ) | | 16,878 |
|
| Other | | 26 |
| | 43 |
| | 40 |
|
| Net cash flow used in investing activities | | (245,127 | ) | | (177,765 | ) | | (149,410 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | — |
| | 98,668 |
| | — |
|
| Retirement of long-term debt | | — |
| | (95,000 | ) | | (116,030 | ) |
| Changes in money pool payable - net | | — |
| | (3,536 | ) | | 3,536 |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (40,000 | ) | | (61,400 | ) | | (7,400 | ) |
| Preferred stock | | (2,828 | ) | | (2,828 | ) | | (2,828 | ) |
| Other | | (352 | ) | | — |
| | (472 | ) |
| Net cash flow used in financing activities | | (43,180 | ) | | (64,096 | ) | | (123,194 | ) |
| Net increase (decrease) in cash and cash equivalents | | 83,972 |
| | 61,602 |
| | (52,939 | ) |
| Cash and cash equivalents at beginning of period | | 61,633 |
| | 31 |
| | 52,970 |
|
| Cash and cash equivalents at end of period | |
| $145,605 |
| |
| $61,633 |
| |
| $31 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | | | |
| | |
|
| Cash paid during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $57,576 |
| |
| $51,509 |
| |
| $54,120 |
|
| Income taxes | |
| $61,333 |
| |
| $19,650 |
| |
| $4,657 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents: | | | | |
| Cash | |
| $1,426 |
| |
| $1,223 |
|
| Temporary cash investments | | 144,179 |
| | 60,410 |
|
| Total cash and cash equivalents | | 145,605 |
| | 61,633 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 56,685 |
| | 78,593 |
|
| Allowance for doubtful accounts | | (718 | ) | | (873 | ) |
| Associated companies | | 34,964 |
| | 21,233 |
|
| Other | | 8,276 |
| | 42,009 |
|
| Accrued unbilled revenues | | 47,284 |
| | 43,374 |
|
| Total accounts receivable | | 146,491 |
| | 184,336 |
|
| Accumulated deferred income taxes | | — |
| | 5,198 |
|
| Fuel inventory - at average cost | | 51,273 |
| | 42,736 |
|
| Materials and supplies - at average cost | | 39,491 |
| | 37,741 |
|
| Prepayments and other | | 5,184 |
| | 7,315 |
|
| TOTAL | | 388,044 |
| | 338,959 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property - at cost (less accumulated depreciation) | | 4,625 |
| | 4,642 |
|
| Escrow accounts | | 41,726 |
| | 41,752 |
|
| TOTAL | | 46,351 |
| | 46,394 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 4,083,933 |
| | 3,999,918 |
|
| Property under capital lease | | 2,942 |
| | 4,185 |
|
| Construction work in progress | | 114,067 |
| | 67,514 |
|
| TOTAL UTILITY PLANT | | 4,200,942 |
| | 4,071,617 |
|
| Less - accumulated depreciation and amortization | | 1,534,522 |
| | 1,516,540 |
|
| UTILITY PLANT - NET | | 2,666,420 |
| | 2,555,077 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Regulatory asset for income taxes - net | | 45,790 |
| | 49,306 |
|
| Other regulatory assets | | 328,681 |
| | 364,747 |
|
| Other | | 2,121 |
| | 4,142 |
|
| TOTAL | | 376,592 |
| | 418,195 |
|
| | | | | |
| TOTAL ASSETS | |
| $3,477,407 |
| |
| $3,358,625 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | |
| | | December 31, |
| | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
| Currently maturing long-term debt | |
| $125,000 |
| |
| $— |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 38,496 |
| | 49,832 |
|
| Other | | 51,502 |
| | 63,300 |
|
| Customer deposits | | 81,583 |
| | 77,753 |
|
| Taxes accrued | | 43,461 |
| | 53,565 |
|
| Interest accrued | | 20,831 |
| | 23,172 |
|
| Deferred fuel costs | | 107,754 |
| | 2,194 |
|
| Other | | 22,754 |
| | 17,533 |
|
| TOTAL | | 491,381 |
| | 287,349 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 810,635 |
| | 800,374 |
|
| Accumulated deferred investment tax credits | | 4,645 |
| | 6,370 |
|
| Asset retirement cost liabilities | | 8,252 |
| | 6,786 |
|
| Accumulated provisions | | 48,062 |
| | 50,142 |
|
| Pension and other postretirement liabilities | | 120,217 |
| | 135,156 |
|
| Long-term debt | | 920,085 |
| | 1,043,859 |
|
| Other | | 11,699 |
| | 16,038 |
|
| TOTAL | | 1,923,595 |
| | 2,058,725 |
|
| | | | | |
| 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 2015 and 2014 | | 199,326 |
| | 199,326 |
|
| Capital stock expense and other | | (690 | ) | | (690 | ) |
| Retained earnings | | 813,414 |
| | 763,534 |
|
| TOTAL | | 1,012,050 |
| | 962,170 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,477,407 |
| |
| $3,358,625 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2015, 2014, and 2013 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Capital Stock Expense and Other | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2012 |
| $199,326 |
| |
| ($690 | ) | |
| $681,010 |
| |
| $879,646 |
|
| Net income | — |
| | — |
| | 82,159 |
| | 82,159 |
|
| Common stock dividends | — |
| | — |
| | (7,400 | ) | | (7,400 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2013 |
| $199,326 |
| |
| ($690 | ) | |
| $752,941 |
| |
| $951,577 |
|
| Net income | — |
| | — |
| | 74,821 |
| | 74,821 |
|
| Common stock dividends | — |
| | — |
| | (61,400 | ) | | (61,400 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2014 |
| $199,326 |
| |
| ($690 | ) | |
| $763,534 |
| |
| $962,170 |
|
| Net income | — |
| | — |
| | 92,708 |
| | 92,708 |
|
| Common stock dividends | — |
| | — |
| | (40,000 | ) | | (40,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (2,828 | ) | | (2,828 | ) |
| Balance at December 31, 2015 |
| $199,326 |
| |
| ($690 | ) | |
| $813,414 |
| |
| $1,012,050 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY MISSISSIPPI, INC. |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $1,396,985 |
| |
| $1,524,193 |
| |
| $1,334,540 |
| |
| $1,120,366 |
| |
| $1,266,470 |
|
| Net Income |
| $92,708 |
| |
| $74,821 |
| |
| $82,159 |
| |
| $46,768 |
| |
| $108,729 |
|
| Total assets |
| $3,477,407 |
| |
| $3,358,625 |
| |
| $3,234,875 |
| |
| $3,337,230 |
| |
| $2,927,645 |
|
| Long-term obligations (a) |
| $972,058 |
| |
| $1,097,182 |
| |
| $1,092,786 |
| |
| $1,108,432 |
| |
| $963,183 |
|
| | | | | | | | | | |
| (a) Includes long-term debt (excluding currently maturing debt), non-current capital lease obligations, and preferred stock without sinking fund. |
| | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $565 |
| |
| $585 |
| |
| $527 |
| |
| $454 |
| |
| $490 |
|
| Commercial | 465 |
| | 481 |
| | 432 |
| | 381 |
| | 401 |
|
| Industrial | 164 |
| | 175 |
| | 156 |
| | 140 |
| | 146 |
|
| Governmental | 47 |
| | 47 |
| | 42 |
| | 37 |
| | 37 |
|
| Total retail | 1,241 |
| | 1,288 |
| | 1,157 |
| | 1,012 |
| | 1,074 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 75 |
| | 153 |
| | 92 |
| | 23 |
| | 104 |
|
| Non-associated companies | 10 |
| | 14 |
| | 24 |
| | 24 |
| | 27 |
|
| Other | 71 |
| | 69 |
| | 62 |
| | 61 |
| | 61 |
|
| Total |
| $1,397 |
| |
| $1,524 |
| |
| $1,335 |
| |
| $1,120 |
| |
| $1,266 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 5,661 |
| | 5,672 |
| | 5,629 |
| | 5,550 |
| | 5,848 |
|
| Commercial | 4,913 |
| | 4,821 |
| | 4,815 |
| | 4,915 |
| | 4,985 |
|
| Industrial | 2,283 |
| | 2,297 |
| | 2,265 |
| | 2,400 |
| | 2,326 |
|
| Governmental | 433 |
| | 414 |
| | 409 |
| | 408 |
| | 415 |
|
| Total retail | 13,290 |
| | 13,204 |
| | 13,118 |
| | 13,273 |
| | 13,574 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,419 |
| | 2,657 |
| | 1,543 |
| | 232 |
| | 431 |
|
| Non-associated companies | 261 |
| | 193 |
| | 304 |
| | 265 |
| | 332 |
|
| Total | 14,970 |
| | 16,054 |
| | 14,965 |
| | 13,770 |
| | 14,337 |
|
ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2016 Compared to 2015
Net income increased $3.9 million primarily due to higher net revenue, partially offset by higher depreciation and amortization expenses, higher interest expense, and lower other income.
2015 Compared to 2014
Net income increased $13.9 million primarily due to lower other operation and maintenance expenses and higher net revenue, partially offset by a higher effective income tax rate.
Net Revenue
2016 Compared to 2015
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 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2015 net revenue |
| $293.9 |
|
| Retail electric price | 39.0 |
|
| Net gas revenue | (2.5 | ) |
| Volume/weather | (5.1 | ) |
| Other | (8.1 | ) |
| 2016 net revenue |
| $317.2 |
|
The retail electric price variance is primarily due to an increase in the purchased power and capacity acquisition cost recovery rider, as approved by the City Council, effective with the first billing cycle of March 2016, primarily related to the purchase of Power Block 1 of the Union Power Station. See Note 14 to the financial statements for discussion of the Union Power Station purchase.
The net gas revenue variance is primarily due to the effect of less favorable weather on residential and commercial sales.
The volume/weather variance is primarily due to a decrease of 112 GWh, or 2%, in billed electricity usage, partially offset by the effect of favorable weather on commercial sales and a 2% increase in the average number of electric customers.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| Amount |
| (In Millions) |
| |
| 2014 net revenue |
| $284.9 |
|
| Volume/weather | 9.8 |
|
| Net gas revenue | (3.1 | ) |
| Other | 2.3 |
|
| 2015 net revenue |
| $293.9 |
|
The volume/weather variance is primarily due to an increase of 165 GWh, or 3%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on commercial sales in 2015 and a 2% increase in the average number of electric customers.
The net gas revenue variance is primarily due to the effect of less favorable weather, primarily on residential sales.
Other Income Statement Variances
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $6.1 million due to lower transmission equalization expenses, as allocated under the System Agreement as compared to the same period in 2015 primarily due to the termination of the System Agreement. See Note 2 to the financial statements for further discussion on the System Agreement termination;
a decrease of $4.4 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm cost recovery; and
a decrease of $3.1 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs.
The decrease was partially offset by:
an increase of $5.7 million in fossil-fueled generation expenses primarily due to an increase as a result of the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by a decrease as a result of the deactivation of Michoud Units 2 and 3 effective May 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase;
an increase of $3.1 million due to an increase in loss reserves; and
an increase of $2.8 million due to higher write-offs of uncollectible customer accounts in 2016 as compared to 2015.
Depreciation and amortization expenses increased primarily due to additions to plant in service, including the purchase of Power Block 1 of the Union Power Station in March 2016, partially offset by the deactivation of Michoud Units 2 and 3 effective May 2016.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Interest expense increased primarily due to the issuance of $110 million of 5.50% Series first mortgage bonds in March 2016 and the issuance of $98.7 million of storm cost recovery bonds in July 2015. See Note 5 to the financial statements for details on long-term debt.
Other income decreased primarily due to an increase in charitable contributions made in 2016 as compared to 2015.
2015 Compared to 2014
Other operation and maintenance expenses decreased primarily due to a decrease of $9.9 million in fossil-fueled generation expenses primarily resulting from a lower scope of work in 2015 and a decrease in asbestos loss reserves in 2015, and a decrease of $3 million due to the cessation of storm damage provisions in August 2015. See Note 2 to the financial statements for further discussion of storm costs recovery.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower electric and gas retail revenues in 2015 as compared to 2014 and a decrease in ad valorem taxes resulting from lower assessments and higher capitalized taxes.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014 were 37.0%, 35.9%, and 30.2%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, and 2014 were as follows:
|
| | | | | | | | | | | |
| | 2016 | | 2015 | | 2014 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $88,876 |
| |
| $42,389 |
| |
| $33,489 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 205,211 |
| | 105,068 |
| | 88,933 |
|
| Investing activities | (322,681 | ) | | (173,460 | ) | | (72,383 | ) |
| Financing activities | 131,662 |
| | 114,879 |
| | (7,650 | ) |
| Net increase in cash and cash equivalents | 14,192 |
| | 46,487 |
| | 8,900 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $103,068 |
| |
| $88,876 |
| |
| $42,389 |
|
Operating Activities
Net cash flow provided by operating activities increased $100.1 million in 2016 primarily due to income tax refunds of $86 million in 2016 as compared to income tax payments of $8.1 million in 2015. Entergy New Orleans had income tax refunds in 2016 and income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The 2016 income tax refunds resulted primarily from deductible temporary differences.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Net cash flow provided by operating activities increased $16.1 million in 2015 primarily due to an increase in net income.
Investing Activities
Net cash flow used in investing activities increased $149.2 million in 2016 primarily due to the purchase of Power Block 1 of the Union Power Station for approximately $237 million in March 2016. See Note 14 to the financial statements for discussion of the Union Power Station purchase. The increase was partially offset by a deposit of $63.9 million into the storm reserve escrow account in July 2015 and money pool activity. See Note 5 to the financial statements for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs.
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 $1.6 million in 2016 compared to increasing $15.4 million in 2015. 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 $101.1 million in 2015 primarily due to:
a deposit of $63.9 million into the storm reserve escrow account in July 2015. See Note 5 for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs;
money pool activity;
an increase in transmission construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014; and
an increase in distribution construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014.
Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $15.4 million in 2015 compared to decreasing $4.3 million in 2014.
Financing Activities
Net cash flow provided by financing activities increased $16.8 million in 2016 primarily due to:
the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction;
the issuance of $100 million of 5.50% Series first mortgage bonds in March 2016; and
the issuance of $85 million of 4% Series first mortgage bonds in May 2016. Entergy New Orleans used the proceeds to pay, prior to maturity, its $33.271 million of 5.6% Series first mortgage bonds due September 2024 and to pay, prior to maturity, its $37.772 million of 5.65% Series first mortgage bonds due September 2029.
The increase was offset by:
the issuance of $98.7 million of storm costs recovery bonds in July 2015;
a $47.8 million capital contribution received from Entergy Corporation in 2016 as compared to an $87.5 million capital contribution received from Entergy Corporation in 2015, both in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station; and
an increase of $11.5 million in common equity distributions in 2016. Equity distributions were lower in 2015 in anticipation of the purchase of Power Block 1 of the Union Power Station.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy New Orleans’s financing activities provided $114.9 million of cash in 2015 compared to using $7.7 million of cash in 2014 primarily due to the issuance of $98.7 million of storm cost recovery bonds in July 2015, and an $87.5 million capital contribution in 2015 in anticipation of Entergy New Orleans’s purchase of Power Block 1 of the Union Power Station, partially offset by the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 2 to the financial statements and “Algiers Asset Transfer” below for further discussion of the Algiers asset transfer and accounting for the transaction.
See Note 5 to the financial statements for more details on long-term debt.
Capital Structure
Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The increase in the debt to capital ratio is primarily due to the issuance of long-term debt in 2016, partially offset by the $47.8 million capital contribution received from Entergy Corporation in March 2016 and an increase in retained earnings.
|
| | | | | |
| | December 31, 2016 | | December 31, 2015 |
| Debt to capital | 50.1 | % | | 48.1 | % |
| Effect of excluding securitization bonds | (5.2 | %) | | (8.1 | %) |
| Debt to capital, excluding securitization bonds (a) | 44.9 | % | | 40.0 | % |
| Effect of subtracting cash | (8.0 | %) | | (10.0 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 36.9 | % | | 30.0 | % |
(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, long-term debt, including the currently maturing portion, and the long-term payable to Entergy Louisiana. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in Note 5 to the financial statements. Entergy New Orleans also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy New Orleans seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy New Orleans may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy New Orleans may receive equity contributions to maintain the targeted capital structure.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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
dividend payments.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2017 | | 2018 | | 2019 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $60 |
| |
| $115 |
| |
| $55 |
|
| Transmission | 5 |
| | 5 |
| | 10 |
|
| Distribution | 45 |
| | 50 |
| | 40 |
|
| Other | 50 |
| | 45 |
| | 40 |
|
| Total |
| $160 |
| |
| $215 |
| |
| $145 |
|
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2017 | | 2018-2019 | | 2020-2021 | | After 2021 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $31 |
| |
| $63 |
| |
| $85 |
| |
| $703 |
| |
| $882 |
|
| Operating leases |
| $2 |
| |
| $4 |
| |
| $3 |
| |
| $2 |
| |
| $11 |
|
| Purchase obligations (b) |
| $209 |
| |
| $407 |
| |
| $410 |
| |
| $3,450 |
| |
| $4,476 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | 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. |
In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $9.9 million to its qualified pension plan and approximately $3.7 million to other postretirement health care and life insurance plans in 2017, although the 2017 required pension contributions will be known with more certainty when the January 1, 2017 valuations are completed, which is expected by April 1, 2017. 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 New Orleans has $138.9 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.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the New Orleans Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to enhance reliability and improve service to customers, including initial investment to support advanced metering; system
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, 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 Notes 5 and 6 to the financial statements.
As a wholly-owned subsidiary of Entergy Corporation, Entergy New Orleans pays dividends from its earnings at a percentage determined monthly. Provisions in Entergy New Orleans’s articles of incorporation relating to preferred stock contains restrictions on the payment of cash dividends or other distributions on its common and preferred stock.
New Orleans Power Station
In June 2016, Entergy New Orleans filed an application with the City Council seeking a public interest determination and authorization to construct the New Orleans Power Station, a 226 megawatt advanced combustion turbine in New Orleans, Louisiana, at the site of the existing Michoud generating facility, which facility was deactivated effective May 31, 2016. The current estimated cost of the New Orleans Power Station is $216 million. A procedural schedule has been established with a decision expected no later than April 2017. Subject to timely approval by the City Council and receipt of other permits and approvals, commercial operation is estimated to occur by late-2019. In January 2017 several intervenors filed testimony opposing the construction of the New Orleans Power Station on various grounds. In February 2017, Entergy New Orleans filed a motion to temporarily suspend the procedural schedule to allow for further analysis regarding its proposal, and that motion was granted. A status conference is scheduled in March 2017.
Gas Infrastructure Rebuild Plan
In September 2016, Entergy Entergy New Orleans submitted to the City Council a request for authorization for Entergy New Orleans to proceed with annual incremental capital funding of $12.5 million for its gas infrastructure rebuild plan, which would replace of all of Entergy New Orleans’s low pressure cast iron, steel, and vintage plastic pipe over a ten-year period commencing in 2017. Entergy New Orleans also proposed that recovery of the investment to fund its gas infrastructure replacement plan be determined in connection with its next base rate case, which is anticipated to be filed in 2018. The City Council has authorized Entergy New Orleans to proceed with its replacement plans at the requested pace until such time that rates resulting from the anticipated 2018 rate case are implemented (approximately 13 months after filing). As a result of the anticipated 2018 rate case, the City Council may establish new overall gas base rates to allow Entergy New Orleans to continue to recover these replacement costs. The City Council has established a schedule for proceedings in advance of the rate case intended to provide an opportunity for evaluation of the gas infrastructure replacement plan that would best serve the public interest and the effect on customers of the approval of any such plan.
Sources of Capital
Entergy New Orleans’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt and preferred stock issuances; and
bank financing under new or existing facilities.
Entergy New Orleans may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Entergy New Orleans’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| $14,215 | | $15,794 | | $442 | | $4,737 |
See Note 4 to the financial statements for a description of the money pool.
Entergy New Orleans has a credit facility in the amount of $25 million scheduled to expire in November 2018. The credit facility allows Entergy New Orleans to issue letters of credit against $10 million of the borrowing capacity of the facility. As of December 31, 2016, there were no cash borrowings and a $0.8 million letter of credit was outstanding under the facility. In addition, Entergy New Orleans is a party to an uncommitted letter of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2016, a $6.2 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy New Orleans obtained authorization from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $100 million at any time outstanding. See Note 4 to the financial statements for further discussion of Entergy New 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 June 2018.
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.
Retail Rates
See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.
In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014 the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the City Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area.
As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for the Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the purchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the purchase of Power Block 1 of the Union Power Station, and a credit to customers of $400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
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. In October 2013 the City Council approved the extension of the Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In February 2017, Entergy New Orleans filed a proposed implementation
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
plan for the Energy Smart program from April 2017 through March 2020. As part of the proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.
Fuel and Purchased Power Cost Recovery
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.
Due to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the City Council and the FERC. In the application, Entergy New Orleans had proposed to credit retail customers $5 million in each of the years 2016 and 2017 if the City Council approved the application in 2016, and to credit retail customers $5 million in each of the years 2018, 2019, and 2020, if an application that is yet to be filed with the FERC is approved by December 31, 2018. When it became clear that City Council approval would not be obtained in 2016, Entergy New Orleans agreed in testimony that it would extend its proposal to credit customers if City Council approval was obtained in the first quarter 2017. Entergy New Orleans still expects that the restructuring can be consummated by December 31, 2017, if the necessary approvals are obtained. In February 2017 the procedural schedule was suspended to allow for settlement discussions. It is not anticipated that NRC approval will be required to engage in the proposed internal restructuring. In January 2017, Entergy Louisiana, through Entergy Corporation’s nuclear operations organization, Entergy Operations, Inc. made a filing, however, with the NRC notifying it of the internal restructuring.
It is currently contemplated that Entergy New Orleans would undertake a multi-step restructuring, which would include the following:
Entergy New Orleans would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans will allocate substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power will assume substantially all of the liabilities of Entergy New Orleans, in a transaction regarded as a merger under the TXBOC. Entergy New Orleans will remain in existence and hold the membership interests in Entergy New Orleans Power.
Entergy New Orleans will contribute the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.
Upon the completion of the restructuring, Entergy New Orleans, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy New Orleans. Entergy New Orleans may modify or supplement the steps to be taken to effectuate the restructuring.
Advanced Metering Infrastructure (AMI) Filing
In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a procedural schedule that provides for a hearing in July 2017.
Algiers Asset TransferState and Local Rate Regulation
In October 2014, Entergy Louisiana andThe rates that Entergy New Orleans filed an application withcharges 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, seeking authorizationis primarily responsible for approval of the rates charged to undertake a transaction that would result incustomers.
Retail Rates
See “Algiers Asset Transfer” below for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving theserve Algiers assets transfer. In May 2015 the parties filed a settlement agreement authorizing the Algiers assets transfer and the settlement agreement was approved by a City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million, subject to closing adjustments. Entergy New Orleans paid Entergy Louisiana $59.6 million, including final true-ups, from available cash and issued a note payable to Entergy Louisiana in the amount of $25.5 million. Because the asset transfer was a transaction involving entities under common control, Entergy New Orleans recognized the assets and liabilities transferred to it at their carrying amounts in the accounts of Entergy Louisiana at the time of the asset transfer. The effect of the Algiers transfer has been retrospectively applied to Entergy New Orleans’s financial statements that are presented in this report.
Results of Operations
Net Income
2015 Compared to 2014
Net income increased $13.9 million primarily due to lower other operation and maintenance expenses and higher net revenue, partially offset by a higher effective income tax rate.
2014 Compared to 2013
Net income increased $18.4 million primarily due to lower other operation and maintenance expenses and higher net revenue, partially offset by a higher effective income tax rate.
Net Revenue
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| Amount |
| (In Millions) |
| |
2014 net revenue |
| $284.9 |
|
Volume/weather | 9.8 |
|
Net gas revenue | (3.1 | ) |
Other | 2.3 |
|
2015 net revenue |
| $293.9 |
|
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The volume/weather variance is primarily due to an increase of 165 GWh, or 3%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on commercial sales in 2015 and a 2% increase in the average number of electric customers.
The net gas revenue variance is primarily due to the effect of less favorable weather, primarily in the residential sector.
2014 Compared to 2013
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 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
2013 net revenue |
| $271.9 |
|
Volume/weather | 5.1 |
|
Net gas revenue | 3.5 |
|
Retail electric price | 2.0 |
|
Transmission revenue | 1.4 |
|
Other | 1.0 |
|
2014 net revenue |
| $284.9 |
|
The volume/weather variance is primarily due to an increase of 137 GWh, or 3%, in billed electricity usage, primarily in the residential and commercial sectors, including the effect of favorable weather on residential sales in 2014 as compared to the prior year andIn March 2013, Entergy Louisiana filed a 2% increase in the average number of electric customers.
The net gas revenue variance is primarily due to the effect of favorable weather, primarily in the residential and commercial sectors.
The retail electric price variance is primarily due to annual base rate increasescase for the Algiers area, effective July 2014, as approvedwhich is in New Orleans and is regulated by the City Council. See Note 2Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request. In January 2014 the financial statements forCity Council Advisors filed direct testimony recommending a further discussionrate increase of these$5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate increases.revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The transmission revenue variance is primarily due to changes as a resultrate increase was effective with bills rendered on and after the first billing cycle of participation in the MISO RTO inJuly 2014.
Other Income Statement Variances
2015 Compared to 2014
Other operation and maintenance expenses decreased primarily due to a decrease of $9.9 million in fossil-fueled generation expenses primarily resulting from a lower scope of work in 2015, a decrease in asbestos loss reserves in 2015, and a decrease of $3 million in loss reserves due to lower storm reserve rider accruals in 2015. See Note 2 to the financial statements for further discussion of storm costs recovery and see “Sources of Capital” below for further discussion of the issuance in July 2015 of securitization bonds to recover storm costs.
Taxes other than income taxes decreased primarily due to a decrease in local franchise taxes resulting from lower electric and gas retail revenues in 2015 as compared to 2014 and a decrease in ad valorem taxes resulting from lower assessments and higher capitalized taxes.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2014 Compared to 2013
Other operation and maintenance expenses decreased primarily due to:
a decrease of $7.7 million in compensation and benefits costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge recognized in September 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
a decrease of $6.7 million in fossil-fueled generation expenses due to an overall lower scope of work done during plant outages as compared to prior year; and
a decrease of $2.4 million in outside regulatory consultant fees.
Income Taxes
The effective income tax rates for 2015, 2014, and 2013 Additional compliance filings were 35.9%, 30.2%, and 15.3%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2015, 2014, and 2013 were as follows:
|
| | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 |
| | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $42,389 |
| |
| $33,489 |
| |
| $9,391 |
|
| | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
|
| Operating activities | 105,068 |
| | 88,933 |
| | 92,550 |
|
| Investing activities | (173,460 | ) | | (72,383 | ) | | (95,890 | ) |
| Financing activities | 114,879 |
| | (7,650 | ) | | 27,438 |
|
| Net increase in cash and cash equivalents | 46,487 |
| | 8,900 |
| | 24,098 |
|
| | | | | | |
| Cash and cash equivalents at end of period |
| $88,876 |
| |
| $42,389 |
| |
| $33,489 |
|
Operating Activities
Net cash flow provided by operating activities increased $16.1 million in 2015 primarily due to an increase in net income.
Net cash flow provided by operating activities decreased $3.6 million in 2014 primarily due to the payment of calendar year 2012 System Agreement bandwidth remedy payments of $15 million to the City of New Orleans in June 2014 for use in the streetlight conversion program, as directed bymade with the City Council an increasein October 2014 for approval of $6.3 million in pension contributions, and income tax paymentsthe form of $4.9 million in 2014 compared to income tax refundscertain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of $1.4 million in 2013. The decrease in cash flow was offset by the timing of collections from customers. See “Critical Accountings Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.capacity
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Investing Activities
Net cash flow used in investing activities increased $101.1 million in 2015 primarily due to:
a deposit of $63.9 million into the storm reserve escrow account in July 2015. See “Sources of Capital” below for a discussion of the issuance in July 2015 of securitization bonds to recover storm costs;
money pool activity;
an increase in transmission construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014; and
an increase in distribution construction expenditures primarily due to a higher scope of work performed in 2015 as compared to 2014.
Increases in Entergy New Orleans’s receivable from the money pool are a use of cash flow, and Entergy New Orleans’s receivable from the money pool increased $15.4 million in 2015 compared to decreasing $4.3 million in 2014. 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 decreased $23.5 million in 2014 primarily due to:
a decrease in fossil-fueled generation construction expenditures primarily due to spending on the Michoud turbine blade replacement projects in 2013;
a decrease in transmission construction expenditures as a result of decreased scope of work in 2014; and
money pool activity.
The decrease was partially offset by receipts from the storm reserve escrow account of $7.8 million in 2013.
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 $4.3 million in 2014 compared to increasing $1.8 million in 2013.
Financing Activities
Entergy New Orleans’s financing activities provided $114.9 million of cash in 2015 compared to using $7.7 million of cash in 2014 primarily due to the issuance of $98.7 million of storm cost recovery bonds in July 2015, as discussed below, and an $87.5 million capital contribution in 2015, partially offset by the purchase of Entergy Louisiana’s Algiers assets in September 2015. The cash portion of the purchase is reflected as a repayment of a long-term payable due to Entergy Louisiana in the cash flow statement. See Note 1 to the financial statements and “Algiers Asset Transfer” above for further discussion of the Algiers asset transfer and accounting for the transaction.
Entergy New Orleans’s financing activities used $7.7 million of cash in 2014 compared to providing $27.4 million of cash in 2013 primarily due to the issuance of $100 million of 3.9% Series first mortgage bonds in June 2013 and $6 million in common stock dividends paid in 2014, partially offset by the retirement of $70 million of 5.25% Series first mortgage bonds in August 2013.
See Note 5 to the financial statements for more details on long-term debt.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy New Orleans’s capitalization is balanced between equity and debt as shown in the following table. The decrease in the debt to capital ratio is due to an $87.5 million capital contribution in 2015 and an increase in retained earnings, offset by an increase in long term debt primarily due to the issuance of $98.7 million of storm cost recovery bonds in July 2015.
|
| | | | | |
| | December 31, 2015 | | December 31, 2014 |
| Debt to capital | 48.1 | % | | 55.1 | % |
| Effect of excluding securitization bonds | (8.1 | %) | | — | % |
| Debt to capital, excluding securitization bonds (a) | 40.0 | % | | 55.1 | % |
| Effect of subtracting cash | (10.0 | %) | | (3.8 | %) |
| Net debt to net capital, excluding securitization bonds (a) | 30.0 | % | | 51.3 | % |
(a) Calculation excludes the securitization bonds, which are non-recourse to Entergy New Orleans.
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings, long-term debt, including the currently maturing portion, and the long-term payable to Entergy Louisiana. Capital consists of debt, preferred stock without sinking fund, and common equity. Net capital consists of capital less cash and cash equivalents. Entergy New Orleans uses the debt to capital ratios excluding securitization bonds in analyzing its financial condition and believes they provide useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because the securitization bonds are non-recourse to Entergy New Orleans, as more fully described in “Sources of Capital” below. Entergy New Orleans uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy New Orleans’s financial condition because net debt indicates Entergy New Orleans’s outstanding debt position that could not be readily satisfied by cash and cash equivalents.
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
dividend payments.
Following are the amounts of Entergy New Orleans’s planned construction and other capital investments.
|
| | | | | | | | | | | |
| | 2016 | | 2017 | | 2018 |
| | (In Millions) |
| Planned construction and capital investment: | | | | | |
| Generation |
| $275 |
| |
| $80 |
| |
| $100 |
|
| Transmission | 5 |
| | 15 |
| | 10 |
|
| Distribution | 35 |
| | 40 |
| | 40 |
|
| Other | 30 |
| | 25 |
| | 25 |
|
| Total |
| $345 |
| |
| $160 |
| |
| $175 |
|
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy New Orleans’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
|
| | | | | | | | | | | | | | | | | | | |
| | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total |
| | (In Millions) |
| Long-term debt (a) |
| $18 |
| |
| $31 |
| |
| $55 |
| |
| $405 |
| |
| $509 |
|
| Operating leases |
| $2 |
| |
| $3 |
| |
| $2 |
| |
| $2 |
| |
| $9 |
|
| Purchase obligations (b) |
| $209 |
| |
| $400 |
| |
| $371 |
| |
| $437 |
| |
| $1,417 |
|
| |
(a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
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(b) | 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. |
In addition to the contractual obligations given above, Entergy New Orleans currently expects to contribute approximately $10.7 million to its pension plan and approximately $3.7 million to other postretirement plans in 2016, although the 2016 required pension contributions will be known with more certainty when the January 1, 2016 valuations are completed, which is expected by April 1, 2016. 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 New Orleans has $53.4 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.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy New Orleans includes specific investments such as the Union Power Station acquisition discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintain reliability and improve service to customers, including initial investment to support smart meter deployment; resource planning, including potential generation projects; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, 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 Notes 5 and 6 to the financial statements.
As a 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.
Union Power Station Purchase Agreement
In December 2014, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas entered into an asset purchase agreement to acquire the Union Power Station, a 1,980 MW (summer rating) power generation facility located near El Dorado, Arkansas, from Union Power Partners, L.P. The Union Power Station consists of four natural gas-fired, combined-cycle gas turbine power blocks, each rated at 495 MW (summer rating). Pursuant to the agreement, Entergy Gulf States Louisiana would acquire two of the power blocks and a 50% undivided ownership interest in certain assets related to the facility, and Entergy Arkansas and Entergy Texas would each acquire one power block and a 25% undivided ownership interest in such related assets. The base purchase price is expected to be approximately $948 million (approximately $237 million for each power block) subject to adjustments. The purchase is contingent upon, among other things, obtaining necessary approvals, including cost recovery, from various federal and state
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regulatory and permitting agencies. Undercosts related to the original termscommencement of commercial operation of the asset purchase agreement, these included regulatory approvalsNinemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the APSC, LPSC, PUCT, and FERC, as well as clearance under the Hart-Scott-Rodino antitrust law.Algiers area.
In December 2014,As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy TexasNew Orleans’s base rates until rates are implemented from a base rate case that must be filed for its applicationelectric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for Certificatethe Algiers area and certain exceptional cost increases or decreases in the base revenue requirement. An additional provision of Convenience and Necessity (CCN)the settlement agreement allows for continued recovery of the revenue requirement associated with the PUCT seeking one of the two necessary PUCT approvals of the acquisition. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the CCN filing. In July 2015, Entergy Texas withdrew its rate casecapacity and together with other parties, filed a motion with the PUCT to dismiss Entergy Texas’s CCN application. In July 2015, the PUCT granted the motion to dismiss the CCN case. The power block originally allocated to Entergy Texas will be acquired by Entergy New Orleans. The acquisitionenergy from Ninemile 6 received by Entergy New Orleans replaces theunder a power purchase agreement with Entergy Gulf States Louisiana that(Algiers PPA). The settlement authorizes Entergy New Orleans to recover the City Council approvedremaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy from Ninemile 6 (Ninemile PPA), which commenced operation in June 2015. December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisitionpurchase of the power blockUnion Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest.
In January 2015, Entergy Gulf States Louisiana filed its application The City Council authorized expansion of the terms of the purchased power and capacity acquisition cost recovery rider to recover the non-fuel purchased power expense from Ninemile 6, the revenue requirement associated with the LPSC for approvalpurchase of Power Block 1 of the acquisitionUnion Power Station, and cost recovery. Supplemental testimony was submitteda credit to customers of $400 thousand monthly beginning June 2016 in July 2015 explaining the reallocation of onerecognition of the power blocks todecrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and clarifying thatthe City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
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 Gulf States Louisiana would own 100%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. In October 2013 the City Council approved the extension of the capacityEnergy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and associated energy of two power blocks. In September 2015, Entergy Gulf States Louisiana agreed to settlement terms with all partiesearn an incentive for Entergy Gulf States Louisiana’s purchase of the two power blocks. In October 2015 the LPSC voted unanimously to approve the uncontested settlement which finds, among other things, that acquisition of Power Blocks 3 and 4 is in the public interest and, therefore, prudent. The business combination of Entergy Gulf States Louisiana and Entergy Louisiana received regulatory approval and closed in October 2015 making Entergy Louisiana the named purchaser of Power Blocks 3 and 4 of the Union Power Station.
meeting program goals. In January 2015 Entergy Arkansas filed its application with the APSCCity Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for approvalthe extended period. Additionally, the City Council approved funding for the Energy Smart program from April 2015 through March 2017 using the remainder of the acquisition andapproximately $12.8 million of 2014 rough production cost recovery. A hearingequalization funds, with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was heldmodified in September 2015. In November 2015 when the APSC issued an order conditionally approving the acquisition and requesting that Entergy Arkansas file compliance testimony reporting on two minor conditions. In January 2016 the APSC issued an order finding that Entergy Arkansas’s December 2015 compliance filing was substantially compliant with its November 2015 order.
In February 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed a notification and report form pursuant to the Hart-Scott-Rodino Antitrust Improvements Act with the United States Department of Justice (DOJ) and Federal Trade Commission with respect to their planned acquisition of the Union Power Station. Union Power Partners, L.P. (UPP), the seller, also filed a notification and report form in February 2015.
In March 2015 the DOJ requested additional information and documentary material from each of the purchasing companies and UPP. Also in March 2015, UPP, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas filed an application with the FERC requesting authorization for the transaction. In April 2015, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas made a filing with the FERC for approval of their proposed accounting treatment of the amortization expenses relating to the acquisition adjustment. Filings were made with the FERC in September 2015 replacing Entergy Texas withCity Council directed Entergy New Orleans as an applicant into use a combination of guaranteed customer savings related to a prior agreement with the filingsCity Council and providing supplemental information.rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In the FERC proceeding requesting authorization for the transaction, in December 2015, UPP, Entergy Arkansas, Entergy Louisiana, as successor in interest to Entergy Gulf States Louisiana, andFebruary 2017, Entergy New Orleans filed their response to the FERC’s November 2015 request for additional information. The public comment period on the December 2015 filing expired in January 2016. No protests were filed. The LPSC, City Council, and APSC have filed submissions with the FERC urging the FERC to promptly consider and approve the transaction.a proposed implementation
Closing of the purchase is expected to be completed promptly following the receipt of FERC approval.
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Sourcesplan for the Energy Smart program from April 2017 through March 2020. As part of Capitalthe proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.
Fuel and Purchased Power Cost Recovery
Entergy New Orleans’s sourceselectric rate schedules include a fuel adjustment tariff designed to meet its capital requirements include: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.
internally generated funds;
cash on hand;
debt and preferred stock issuances; and
bank financing under new or existing facilities.
Entergy New Orleans may refinance, redeem, or otherwise retire debt and preferred stock prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy New Orleans’s receivables fromgas rate schedules include a purchased gas adjustment to reflect estimated gas costs for the money pool were as follows as of December 31 for each ofbilling month, adjusted by a surcharge or credit similar to that included in the following years.
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| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| $15,794 | | $442 | | $4,737 | | $2,923 |
See Note 4Due to higher fuel costs associated in part with the financial statementsextended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for a description of the money pool.
December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans has a credit facilityto cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the amount of $25 million scheduled to expire in November 2018. No borrowings were outstanding under the facility as of December 31, 2015. over- or under-recovery account.
Internal Restructuring
In addition,July 2016, Entergy New Orleans isfiled an application with the City Council seeking authorization to undertake a party to an uncommitted letterrestructuring that would result in the transfer of credit facility as a means to post collateral to support its obligations under MISO. As of December 31, 2015, a $1.4 million letter of credit was outstanding under Entergy New Orleans’s letter of credit facility. See Note 4 to the financial statements for additional discussionsubstantially all of the credit facilities.
Entergy New Orleans obtained authorization from the FERC through October 2017 for short-term borrowings not to exceed an aggregate amount of $100 million at any time outstanding. See Note 4 to the financial statements for further discussion of Entergy New Orleans’s short-term borrowing limits. The long-term securities issuancesassets and operations of Entergy New Orleans are limited to amounts authorizeda new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the City Council and the current authorization extends through July 2016.
FERC. In May 2015the application, Entergy New Orleans had proposed to credit retail customers $5 million in each of the years 2016 and 2017 if the City Council issued a financing order authorizingapproved the issuanceapplication in 2016, and to credit retail customers $5 million in each of securitization bondsthe years 2018, 2019, and 2020, if an application that is yet to recover Entergy New Orleans’s Hurricane Isaac storm restoration costs of $31.8 million, including carrying costs, the costs of funding and replenishing the storm recovery reserve in the amount of $63.9 million, and approximately $3 million of up-front financing costs associatedbe filed with the securitization. In July 2015,FERC is approved by December 31, 2018. When it became clear that City Council approval would not be obtained in 2016, Entergy New Orleans Storm Recovery Funding I, L.L.C., a company wholly owned and consolidated byagreed in testimony that it would extend its proposal to credit customers if City Council approval was obtained in the first quarter 2017. Entergy New Orleans issued $98.7 million of storm cost recovery bonds. The bonds have a coupon of 2.67% and an expected maturity date of June 2024. Althoughstill expects that the principal amountrestructuring can be consummated by December 31, 2017, if the necessary approvals are obtained. In February 2017 the procedural schedule was suspended to allow for settlement discussions. It is not due untilanticipated that NRC approval will be required to engage in the date given above,proposed internal restructuring. In January 2017, Entergy Louisiana, through Entergy Corporation’s nuclear operations organization, Entergy Operations, Inc. made a filing, however, with the NRC notifying it of the internal restructuring.
It is currently contemplated that Entergy New Orleans Storm Recovery Funding expects to make principal payments onwould undertake a multi-step restructuring, which would include the bonds over the next five years in the amounts of $11.4 million for 2016, $10.6 million for 2017, $11 million for 2018, $11.2 million for 2019, and $11.6 million for 2020. With the proceeds, following:
Entergy New Orleans Storm Recovery Funding purchased from would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.
Under 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 consolidatedTexas Business Organizations Code (TXBOC), Entergy New Orleans balance sheet. The creditorswill allocate substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power will assume substantially all of the liabilities of Entergy New Orleans, do not have recourse toin a transaction regarded as a merger under the assets or revenues ofTXBOC. Entergy New Orleans Storm Recovery Funding, includingwill remain in existence and hold the storm recovery property, and the creditors ofmembership interests in Entergy New Orleans Storm Recovery Funding do not have recourse to the assets or revenues of Entergy New Orleans. Power.
Entergy New Orleans has no payment obligations towill contribute the membership interests in Entergy New Orleans Storm Recovery Funding exceptPower to remit storm recovery charge collections.an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy
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Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.
Upon the completion of the restructuring, Entergy New Orleans, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy New Orleans. Entergy New Orleans may modify or supplement the steps to be taken to effectuate the restructuring.
Advanced Metering Infrastructure (AMI) Filing
In October 2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a procedural schedule that provides for a hearing in July 2017.
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 and Formula Rate PlansRetail Rates
In April 2009See “Algiers Asset Transfer” below for discussion of the City Council approved a three-year formula rate plan fortransfer from Entergy Louisiana to 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.of certain assets that serve Algiers customers.
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 also requested to increase annual funding for its storm reserve by approximately $5.7 million for 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. In August 2013 the City Council unanimously approved a settlement of all issues in the formula rate plan proceeding. Pursuant to the terms of the settlement, Entergy New Orleans implemented an approximately $1.625 million net decrease to the electric rates that were in effect prior to the electric rate increase implemented in October 2012, with no change in gas rates. Entergy New Orleans refunded to customers approximately $6 million over the four-month period from September 2013 through December 2013 to make the electric rate decrease effective as of the first billing cycle of October 2012. Entergy New Orleans had previously recorded provisions for the majority of the refund to customers, but recorded an additional $1.1 million provision in second quarter 2013 as a result of the settlement. Entergy New Orleans’s formula rate plan ended with the 2011 test year and has not been extended.
In March 2013, Entergy Louisiana filed a rate case for the Algiers area, which is in New Orleans and is regulated by the City Council. Entergy Louisiana requested a rate increase of $13 million over three years, including a 10.4% return on common equity and a formula rate plan mechanism identical to its LPSC request made in February 2013.request. In January 2014 the City Council Advisors filed direct testimony recommending a rate increase of $5.56 million over three years, including an 8.13% return on common equity. In June 2014 the City Council unanimously approved a settlement that includes the following:
a $9.3 million base rate revenue increase to be phased in on a levelized basis over four years;
recovery of an additional $853 thousand annually through a MISO recovery rider; and
the adoption of a four-year formula rate plan requiring the filing of annual evaluation reports in May of each year, commencing May 2015, with resulting rates being implemented in October of each year. The formula rate plan includes a midpoint target authorized return on common equity of 9.95% with a +/- 40 basis point bandwidth.
The rate increase was effective with bills rendered on and after the first billing cycle of July 2014. Additional compliance filings were made with the City Council in October 2014 for approval of the form of certain rate riders, including among others, a Ninemile 6 non-fuel cost recovery interim rider, allowing for contemporaneous recovery of capacity
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costs related to the commencement of commercial operation of the Ninemile 6 generating unit and a purchased power capacity cost recovery rider. The monthly Ninemile 6 cost recovery interim rider was implemented in December 2014 to initially collect $915 thousand from Entergy Louisiana customers in the Algiers area. See “Algiers Asset Transfer ” above
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for discussion of the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that serve Algiers customers.
As a provision of the settlement agreement approved by the City Council in May 2015 providing for the Algiers asset transfer, it was agreed that, with limited exceptions, no action may be taken with respect to Entergy New Orleans’s base rates until rates are implemented from a base rate case that must be filed for its electric and gas operations in 2018. This provision eliminated the formula rate plan applicable to Algiers operations. The limited exceptions include continued implementation of the remaining two years of the four-year phased-in rate increase for its operations in the Algiers area and certain exceptional cost increases or decreases in itsthe base revenue requirement. An additional provision of the settlement agreement allows for continued recovery of the revenue requirement associated with the capacity and energy from Ninemile 6 received by Entergy New Orleans under a power purchase agreement with Entergy Louisiana (Algiers PPA). The settlement authorizes Entergy New Orleans to recover the remaining revenue requirement related to the Algiers PPA through base rates charged to Algiers customers. The settlement also provided for continued implementation of the Algiers MISO recovery rider.
In addition to the Algiers PPA, Entergy New Orleans has a separate power purchase agreement with Entergy Louisiana for 20% of the capacity and energy of thefrom Ninemile Unit 6 generating station (Ninemile PPA), which commenced operation in December 2014. Initially, recovery of the non-fuel costs associated with the Ninemile PPA was authorized through a special Ninemile 6 rider billed to only Entergy New Orleans customers outside of Algiers.
In August 2015, Entergy New Orleans filed an application with the City Council seeking authorization to proceed with the acquisitionpurchase of Union Power Block 1, with an expected base purchase price of approximately $237 million, subject to adjustments, and seeking approval of the recovery of the associated costs. In November 2015 the City Council issued written resolutions and an order approving an agreement in principle between Entergy New Orleans and City Council advisors providing that the purchase of Union Power Block 1 and related assets by Entergy New Orleans is prudent and in the public interest. The City Council authorized expansion of the special Ninemile 6terms of the purchased power and capacity acquisition cost recovery rider discussed above, to coverrecover the non-fuel purchased power expense from Ninemile 6, as well as the revenue requirement associated with the acquisitionpurchase of Union Power Block 1 upon closing of the transaction. This rider will also includeUnion Power Station, and a credit to customers of $4.8 million annually once$400 thousand monthly beginning June 2016 in recognition of the decrease in other operation and maintenance expenses that would result with the deactivation of Michoud Units 2 and 3 occurs.3. In March 2016, Entergy New Orleans purchased Power Block 1 of the Union Power Station for approximately $237 million and initiated recovery of these costs with March 2016 bills. In July 2016, Entergy New Orleans and the City Council Utility Committee agreed to a temporary increase in the Michoud credit to customers to a total of $1.4 million monthly for August 2016 through December 2016.
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. In October 2013 the City Council approved the extension of the current Energy Smart program through December 2014. The City Council approved the use of $3.5 million of rough production cost equalization funds for program costs. In addition, Entergy New Orleans will be allowed to recover its lost contribution to fixed costs and to earn an incentive for meeting program goals. In January 2015 the City Council approved extending the Energy Smart program through March 2015 and using $1.2 million of rough production cost equalization funds to cover program costs for the extended period. Additionally, the City Council approved funding for the Energy Smart 2 programsprogram from April 2015 through March 2017 using the remainder of the approximately $12.8 million of 2014 rough production cost equalization funds, and with any remaining costs being recovered through the fuel adjustment clause. This funding methodology was modified in November 2015 when the City Council directed Entergy New Orleans to use a combination of guaranteed customer savings related to a prior agreement with the City Council and rough production cost equalization funds to cover program costs prior to recovering any costs through the fuel adjustment clause. In February 2017, Entergy New Orleans filed a proposed implementation
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plan for the Energy Smart program from April 2017 through March 2020. As part of the proposal, Entergy New Orleans requested that the City Council identify its desired level of funding for the program during this time period and approve a cost recovery mechanism.
Fuel and Purchased Power Cost Recovery
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
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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.
Storm Cost RecoveryDue to higher fuel costs associated in part with the extended Grand Gulf outage and the partially simultaneous Union Power Block 1 planned outage, for the December 2016, January 2017, and February 2017 billing months, the City Council authorized Entergy New Orleans to cap the fuel adjustment charge billed to customers at $0.035 per kWh and to defer billing of all fuel costs in excess of the capped amount by including such costs in the over- or under-recovery account.
Internal Restructuring
In July 2016, Entergy New Orleans filed an application with the City Council seeking authorization to undertake a restructuring that would result in the transfer of substantially all of the assets and operations of Entergy New Orleans to a new entity, which would ultimately be owned by an existing Entergy subsidiary holding company. The restructuring is subject to regulatory review and approval by the City Council and the FERC. In the application, Entergy New Orleans had proposed to credit retail customers $5 million in each of the years 2016 and 2017 if the City Council approved the application in 2016, and to credit retail customers $5 million in each of the years 2018, 2019, and 2020, if an application that is yet to be filed with the FERC is approved by December 31, 2018. When it became clear that City Council approval would not be obtained in 2016, Entergy New Orleans agreed in testimony that it would extend its proposal to credit customers if City Council approval was obtained in the first quarter 2017. Entergy New Orleans still expects that the restructuring can be consummated by December 31, 2017, if the necessary approvals are obtained. In February 2017 the procedural schedule was suspended to allow for settlement discussions. It is not anticipated that NRC approval will be required to engage in the proposed internal restructuring. In January 2017, Entergy Louisiana, through Entergy Corporation’s nuclear operations organization, Entergy Operations, Inc. made a filing, however, with the NRC notifying it of the internal restructuring.
It is currently contemplated that Entergy New Orleans would undertake a multi-step restructuring, which would include the following:
Entergy New Orleans would redeem its outstanding preferred stock at a price of approximately $21 million, which includes an expected call premium of approximately $819,000, plus any accumulated and unpaid dividends.
Entergy New Orleans would convert from a Louisiana corporation to a Texas corporation.
Under the Texas Business Organizations Code (TXBOC), Entergy New Orleans will allocate substantially all of its assets to a new subsidiary, Entergy New Orleans Power, LLC, a Texas limited liability company (Entergy New Orleans Power), and Entergy New Orleans Power will assume substantially all of the liabilities of Entergy New Orleans, in a transaction regarded as a merger under the TXBOC. Entergy New Orleans will remain in existence and hold the membership interests in Entergy New Orleans Power.
Entergy New Orleans will contribute the membership interests in Entergy New Orleans Power to an affiliate (Entergy Utility Holding Company, LLC, a Texas limited liability company and subsidiary of Entergy
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Corporation). As a result of the contribution, Entergy New Orleans Power will be a wholly-owned subsidiary of Entergy Utility Holding Company, LLC.
Entergy New Orleans will change its name to Entergy Utility Group, Inc., and Entergy New Orleans Power will then change its name to Entergy New Orleans, LLC.
Upon the completion of the restructuring, Entergy New Orleans, LLC will hold substantially all of the assets, and will have assumed substantially all of the liabilities, of Entergy New Orleans. Entergy New Orleans may modify or supplement the steps to be taken to effectuate the restructuring.
Advanced Metering Infrastructure (AMI) Filing
In October 2006,2016, Entergy New Orleans filed an application seeking a finding from the City Council that Entergy New Orleans’s deployment of advanced electric and gas metering infrastructure is in the public interest. Entergy New Orleans proposed to deploy advanced meters that enable two-way data communication; design and build a secure and reliable network to support such communications; and implement support systems. AMI is intended to serve as the foundation of Entergy New Orleans’s modernized power grid. The filing identified a number of quantified and unquantified benefits, and Entergy New Orleans provided a cost/benefit analysis showing that its combined electric and gas AMI deployment is expected to produce a nominal net benefit to customers of $101 million. Entergy New Orleans also sought to continue to include in rate base the remaining book value at December 31, 2015, approximately $21 million, of the existing electric meters and also to depreciate those assets using current depreciation rates. Entergy New Orleans proposed a 15-year depreciable life for the new advanced meters, the three-year deployment of which is expected to begin in 2019. Subject to approval by the City Council, deployment of the information technology infrastructure is expected to begin in 2017 and deployment of the communications network is expected to begin in 2018. Entergy New Orleans proposes to recover the cost of AMI through the implementation of a customer charge, net of certain benefits, phased in over the period 2019 through 2022. In January 2017 the City Council approved a rate filingprocedural schedule that provides for a hearing in July 2017.
Algiers Asset Transfer
In October 2014, Entergy Louisiana and Entergy New Orleans filed an application with the City Council seeking authorization to undertake a transaction that would result in the transfer from Entergy Louisiana to Entergy New Orleans of certain assets that supported the provision of service to Entergy Louisiana’s customers in Algiers. In April 2015 the FERC issued an order approving the Algiers assets transfer. In May 2015 the parties filed a settlement agreement that, among other things, authorizedauthorizing the Algiers assets transfer and the settlement agreement was approved by a $75City Council resolution in May 2015. On September 1, 2015, Entergy Louisiana transferred its Algiers assets to Entergy New Orleans for a purchase price of approximately $85 million. Entergy New Orleans paid Entergy Louisiana $59.6 million, storm reserve for damageincluding final true-ups, from future storms, which will be created overavailable cash and issued a ten-year period through a storm reserve rider that begannote payable to Entergy Louisiana in March 2007. These storm reserve funds are held in a restricted escrow account until needed in response to a storm. the amount of $25.5 million.
Storm Cost Recovery
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 were $47.3 million. Entergy New Orleans withdrew $17.4 million from the storm reserve escrow account to partially offset these costs. In February 2014, Entergy New Orleans made a filing with the City Council seeking certification of the Hurricane Isaac costs. In January 2015 the City Council issued a resolution approving the terms of a joint agreement in principle filed by Entergy New Orleans, Entergy Louisiana, and the City Council Advisors determining, among other things, that Entergy New Orleans’s prudently-incurred storm recovery costs were $49.3 million, of which $31.7 million, net of reimbursements from the storm reserve escrow account, remainsremained recoverable from Entergy New Orleans’s electric customers. The resolution also directsdirected Entergy New Orleans to file an application to securitize the unrecovered Council-approved storm recovery costs of $31.7 million pursuant to the Louisiana Electric Utility Storm Recovery Securitization Act (Louisiana Act 64). In addition, the resolution found that it iswas reasonable for Entergy New Orleans to include in the principal amount of its potential securitization the costs to fund and replenish Entergy New Orleans’s storm reserve in an amount that achievesachieved the Council-approved funding level of $75 million. In January
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
2015, in compliance with that directive, Entergy New Orleans filed with the City Council an application requesting that the City Council grant a financing order authorizing the financing of Entergy New Orleans’s storm costs, storm reserves, and issuance costs pursuant to Louisiana Act 64. In April 2015 the City Council’s Utility advisors filed direct testimony recommending that the proposed securitization be approved subject to certain limited modifications, and Entergy New Orleans filed rebuttal testimony later in April 2015. In May 2015 the parties entered into an agreement in principle and the City Council issued a financing order authorizing Entergy New Orleans to issue storm recovery bonds in the aggregate amount of $98.7 million, including $31.8 million for recovery of Entergy New Orleans’s Hurricane Isaac storm recovery costs, including carrying costs, $63.9 million to fund and replenish Entergy New Orleans’s storm reserve, and approximately $3 million for estimated up-front financing costs associated with the securitization. See Note 5 to the financial statements for discussion of the issuance of the securitization bonds in July 2015.
Show Cause Order
In July 2016 the City Council approved the issuance of a show cause order, which directs Entergy New Orleans to make a filing on or before September 29, 2016 to demonstrate the reasonableness of its actions or positions with regard to certain issues in four existing dockets that relate to Entergy New Orleans’s: (i) storm hardening proposal; (ii) 2015 integrated resource plan; (iii) gas infrastructure rebuild proposal; and (iv) proposed sizing of the New Orleans Power Station and its community outreach prior to the filing. In September 2016, Entergy New Orleans filed its response to the City Council’s show cause order. The City Council has not established any further procedural schedule with regard to this proceeding.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization” and “System Agreement” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Environmental Risks
Entergy New 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’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’s financial position or results of operations.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy New Orleans records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Taxation and a receivable,Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of the unbilled receivable at the beginning of the periodEntergy Corporation 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 periodSubsidiaries Management’s Financial Discussion 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, in addition to changes in certain components of the calculation.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy New Orleans’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in 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 2015 Qualified Pension Cost | | Impact on 2015 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $600 | | $6,166 | | (0.25%) | | $450 | |
| $6,312 |
|
| Rate of return on plan assets | | (0.25%) | | $330 | | $— | | (0.25%) | | $373 | | $- |
|
| Rate of increase in compensation | | 0.25% | | $209 | | $934 | | 0.25% | | $146 | |
| $775 |
|
Entergy New Orleans, Inc. 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 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $90 | | $1,406 | | (0.25%) | |
| $85 |
| | $1,465 |
| Health care cost trend | | 0.25% | | $247 | | $1,478 | | 0.25% | |
| $168 |
| | $1,185 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Entergy New Orleans, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Costs and Funding
Total qualified pension cost for Entergy New Orleans in 20152016 was $9$5.6 million. Entergy New Orleans anticipates 20162017 qualified pension cost to be $5.6$5.1 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $1.7 million. Entergy New Orleans contributed $10.9$10.7 million to its pension plans in 20152016 and estimates 2016-20182017 pension contributions will approximate $27.8be approximately $9.9 million, including $10.7 million in 2016, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total postretirement health care and life insurance benefit income for Entergy New Orleans in 20152016 was $1.6$2.8 million. Entergy New Orleans expects 20162017 postretirement health care and life insurance benefit income of approximately $2.8$2.5 million. In 2016, Entergy New Orleans refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $548 thousand. Entergy New Orleans contributed $3.7$4.3 million to its other postretirement plans in 20152016 and expects 2016-2018estimates 2017 contributions to approximate $7.7 million, includingwill be approximately $3.7 million in 2016.million.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $15 million in the qualified pension benefit obligation and $3.6 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.2 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established byIn 2016, the Employee Retirement Income Security Act of 1974, as amended andmortality projection scale was updated to MP-2016, with no change in the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries newbase mortality assumptions until after 2015, possibly 2016.table assumption.
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.
Other Contingencies
Entergy New Orleans, Inc.Corporation and Subsidiaries
Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy New Orleans, Inc. and Subsidiaries
New Orleans, Louisiana
We have audited the accompanying consolidated balance sheets of Entergy New Orleans, Inc. and Subsidiaries (the “Company”) as of December 31, 20152016 and 2014,2015, and the related consolidated income statements, and consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 400397 through 404402 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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 New Orleans, Inc. and Subsidiaries as of December 31, 20152016 and 2014,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
As discussed in Note 1 to the consolidated financial statements, on September 1, 2015 Entergy Louisiana, LLC transferred its Algiers assets to the Company. The Algiers transfer was accounted for as a business combination between entities under common control. Consequently, the consolidated financial statements presented herein have been retrospectively adjusted to reflect the combined assets and operations of the Company and Algiers for all periods presented.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $586,820 |
| |
| $584,322 |
| |
| $625,088 |
|
| Natural gas | | 78,643 |
| | 87,124 |
| | 110,104 |
|
| TOTAL | | 665,463 |
| | 671,446 |
| | 735,192 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 40,489 |
| | 96,307 |
| | 178,347 |
|
| Purchased power | | 299,551 |
| | 277,851 |
| | 271,159 |
|
| Other operation and maintenance | | 117,471 |
| | 119,087 |
| | 131,549 |
|
| Taxes other than income taxes | | 48,078 |
| | 46,660 |
| | 49,964 |
|
| Depreciation and amortization | | 51,737 |
| | 43,205 |
| | 45,426 |
|
| Other regulatory charges - net | | 8,258 |
| | 3,366 |
| | 791 |
|
| TOTAL | | 565,584 |
| | 586,476 |
| | 677,236 |
|
| | | | | | | |
| OPERATING INCOME | | 99,879 |
| | 84,970 |
| | 57,956 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 1,178 |
| | 1,404 |
| | 1,750 |
|
| Interest and investment income | | 256 |
| | 73 |
| | 95 |
|
| Miscellaneous - net | | (3,144 | ) | | 339 |
| | 614 |
|
| TOTAL | | (1,710 | ) | | 1,816 |
| | 2,459 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 21,061 |
| | 17,312 |
| | 16,820 |
|
| Allowance for borrowed funds used during construction | | (446 | ) | | (641 | ) | | (885 | ) |
| TOTAL | | 20,615 |
| | 16,671 |
| | 15,935 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 77,554 |
| | 70,115 |
| | 44,480 |
|
| | | | | | | |
| Income taxes | | 28,705 |
| | 25,190 |
| | 13,450 |
|
| | | | | | | |
| NET INCOME | | 48,849 |
| | 44,925 |
| | 31,030 |
|
| | | | | | | |
| Preferred dividend requirements and other | | 965 |
| | 965 |
| | 965 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $47,884 |
| |
| $43,960 |
| |
| $30,065 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
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|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED INCOME STATEMENTS |
| | | |
| | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) |
| | | | | | | |
| OPERATING REVENUES | | | | | | |
| Electric | |
| $584,322 |
| |
| $625,088 |
| |
| $564,631 |
|
| Natural gas | | 87,124 |
| | 110,104 |
| | 95,115 |
|
| TOTAL | | 671,446 |
| | 735,192 |
| | 659,746 |
|
| | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 96,307 |
| | 178,347 |
| | 123,662 |
|
| Purchased power | | 277,851 |
| | 271,159 |
| | 263,318 |
|
| Other operation and maintenance | | 119,087 |
| | 131,549 |
| | 146,754 |
|
| Taxes other than income taxes | | 46,660 |
| | 49,964 |
| | 50,431 |
|
| Depreciation and amortization | | 43,205 |
| | 45,426 |
| | 43,990 |
|
| Other regulatory charges - net | | 3,366 |
| | 791 |
| | 821 |
|
| TOTAL | | 586,476 |
| | 677,236 |
| | 628,976 |
|
| | | | | | | |
| OPERATING INCOME | | 84,970 |
| | 57,956 |
| | 30,770 |
|
| | | | | | | |
| OTHER INCOME | | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 1,404 |
| | 1,750 |
| | 1,598 |
|
| Interest and investment income | | 73 |
| | 95 |
| | 100 |
|
| Miscellaneous - net | | 339 |
| | 614 |
| | (1,483 | ) |
| TOTAL | | 1,816 |
| | 2,459 |
| | 215 |
|
| | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
|
| Interest expense | | 17,312 |
| | 16,820 |
| | 16,892 |
|
| Allowance for borrowed funds used during construction | | (641 | ) | | (885 | ) | | (792 | ) |
| TOTAL | | 16,671 |
| | 15,935 |
| | 16,100 |
|
| | | | | | | |
| INCOME BEFORE INCOME TAXES | | 70,115 |
| | 44,480 |
| | 14,885 |
|
| | | | | | | |
| Income taxes | | 25,190 |
| | 13,450 |
| | 2,277 |
|
| | | | | | | |
| NET INCOME | | 44,925 |
| | 31,030 |
| | 12,608 |
|
| | | | | | | |
| Preferred dividend requirements and other | | 965 |
| | 965 |
| | 965 |
|
| | | | | | | |
| EARNINGS APPLICABLE TO COMMON STOCK | |
| $43,960 |
| |
| $30,065 |
| |
| $11,643 |
|
| | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $48,849 |
| |
| $44,925 |
| |
| $31,030 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 51,737 |
| | 43,205 |
| | 45,426 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 140,283 |
| | 22,180 |
| | 24,380 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | (3,888 | ) | | 7,878 |
| | 21,098 |
|
| Fuel inventory | | 71 |
| | 1,104 |
| | (17 | ) |
| Accounts payable | | 15,434 |
| | 2,738 |
| | (7,702 | ) |
| Interest accrued | | 534 |
| | 1,270 |
| | (63 | ) |
| Deferred fuel costs | | (33,839 | ) | | (182 | ) | | 5,409 |
|
| Other working capital accounts | | 2,480 |
| | (2,995 | ) | | (18,030 | ) |
| Provisions for estimated losses | | 4,326 |
| | 58,310 |
| | 10,877 |
|
| Other regulatory assets | | (2,784 | ) | | (70,471 | ) | | (41,517 | ) |
| Pension and other postretirement liabilities | | (6,859 | ) | | (18,831 | ) | | 29,942 |
|
| Other assets and liabilities | | (11,133 | ) | | 15,937 |
| | (11,900 | ) |
| Net cash flow provided by operating activities | | 205,211 |
| | 105,068 |
| | 88,933 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (90,512 | ) | | (91,928 | ) | | (70,903 | ) |
| Allowance for equity funds used during construction | | 1,178 |
| | 1,404 |
| | 1,750 |
|
| Payment for purchase of plant | | (237,335 | ) | | — |
| | — |
|
| Investments in affiliates | | (38 | ) | | — |
| | — |
|
| Changes in money pool receivable - net | | 1,579 |
| | (15,352 | ) | | 4,295 |
|
| Payments to storm reserve escrow account | | (438 | ) | | (68,886 | ) | | (7,525 | ) |
| Receipts from storm reserve escrow account | | 3 |
| | 5,922 |
| | — |
|
| Changes in securitization account | | 2,882 |
| | (4,620 | ) | | — |
|
| Net cash flow used in investing activities | | (322,681 | ) | | (173,460 | ) | | (72,383 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 240,604 |
| | 95,367 |
| | — |
|
| Retirement of long-term debt | | (132,526 | ) | | — |
| | — |
|
| Repayment of long-term payable due to Entergy Louisiana | | (4,973 | ) | | (59,610 | ) | | — |
|
| Capital contributions from parent | | 47,750 |
| | 87,500 |
| | — |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (18,720 | ) | | (7,250 | ) | | (6,000 | ) |
| Preferred stock | | (965 | ) | | (965 | ) | | (965 | ) |
| Other | | 492 |
| | (163 | ) | | (685 | ) |
| Net cash flow provided by (used in) financing activities | | 131,662 |
| | 114,879 |
| | (7,650 | ) |
| Net increase in cash and cash equivalents | | 14,192 |
| | 46,487 |
| | 8,900 |
|
| Cash and cash equivalents at beginning of period | | 88,876 |
| | 42,389 |
| | 33,489 |
|
| Cash and cash equivalents at end of period | |
| $103,068 |
| |
| $88,876 |
| |
| $42,389 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $19,317 |
| |
| $14,951 |
| |
| $15,877 |
|
| Income taxes | |
| ($85,962 | ) | |
| $8,110 |
| |
| $4,871 |
|
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CASH FLOWS |
| | | |
| | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 |
| | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | |
| Net income | |
| $44,925 |
| |
| $31,030 |
| |
| $12,608 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | |
| Depreciation and amortization | | 43,205 |
| | 45,426 |
| | 43,990 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 22,180 |
| | 24,380 |
| | (7,439 | ) |
| Changes in assets and liabilities: | | |
| | |
| | |
|
| Receivables | | 7,878 |
| | 21,098 |
| | (8,215 | ) |
| Fuel inventory | | 1,104 |
| | (17 | ) | | (1,222 | ) |
| Accounts payable | | 2,738 |
| | (7,702 | ) | | 5,987 |
|
| Interest accrued | | 1,270 |
| | (63 | ) | | 581 |
|
| Deferred fuel costs | | (182 | ) | | 5,409 |
| | 22,622 |
|
| Other working capital accounts | | (2,995 | ) | | (18,030 | ) | | 3,194 |
|
| Provisions for estimated losses | | 58,310 |
| | 10,877 |
| | (31 | ) |
| Other regulatory assets | | (70,471 | ) | | (41,517 | ) | | 62,586 |
|
| Pension and other postretirement liabilities | | (18,831 | ) | | 29,942 |
| | (51,293 | ) |
| Other assets and liabilities | | 15,937 |
| | (11,900 | ) | | 9,182 |
|
| Net cash flow provided by operating activities | | 105,068 |
| | 88,933 |
| | 92,550 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
|
| Construction expenditures | | (91,928 | ) | | (70,903 | ) | | (95,766 | ) |
| Allowance for equity funds used during construction | | 1,404 |
| | 1,750 |
| | 1,598 |
|
| Changes in money pool receivable - net | | (15,352 | ) | | 4,295 |
| | (1,814 | ) |
| Payments to storm reserve escrow account | | (68,886 | ) | | (7,525 | ) | | (7,663 | ) |
| Receipts from storm reserve escrow account | | 5,922 |
| | — |
| | 7,755 |
|
| Change in securitization account | | (4,620 | ) | | — |
| | — |
|
| Net cash flow used in investing activities | | (173,460 | ) | | (72,383 | ) | | (95,890 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 95,367 |
| | — |
| | 98,471 |
|
| Retirement of long-term debt | | — |
| | — |
| | (70,068 | ) |
| Repayment of long-term payable due to Entergy Louisiana | | (59,610 | ) | | — |
| | — |
|
| Capital contributions from parent | | 87,500 |
| | — |
| | — |
|
| Dividends paid: | | |
| | |
| | |
|
| Common stock | | (7,250 | ) | | (6,000 | ) | | — |
|
| Preferred stock | | (965 | ) | | (965 | ) | | (965 | ) |
| Other | | (163 | ) | | (685 | ) | | — |
|
| Net cash flow provided by (used in) financing activities | | 114,879 |
| | (7,650 | ) | | 27,438 |
|
| Net increase in cash and cash equivalents | | 46,487 |
| | 8,900 |
| | 24,098 |
|
| Cash and cash equivalents at beginning of period | | 42,389 |
| | 33,489 |
| | 9,391 |
|
| Cash and cash equivalents at end of period | |
| $88,876 |
| |
| $42,389 |
| |
| $33,489 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $14,951 |
| |
| $15,877 |
| |
| $15,153 |
|
| Income taxes | |
| $8,110 |
| |
| $4,871 |
| |
| ($1,448 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
|
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents | | | | |
| Cash | |
| $28 |
| |
| $1,068 |
|
| Temporary cash investments | | 103,040 |
| | 87,808 |
|
| Total cash and cash equivalents | | 103,068 |
| | 88,876 |
|
| Securitization recovery trust account | | 1,738 |
| | 4,620 |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 43,536 |
| | 34,627 |
|
| Allowance for doubtful accounts | | (3,059 | ) | | (268 | ) |
| Associated companies | | 16,811 |
| | 23,248 |
|
| Other | | 5,926 |
| | 3,753 |
|
| Accrued unbilled revenues | | 18,254 |
| | 17,799 |
|
| Total accounts receivable | | 81,468 |
| | 79,159 |
|
| Deferred fuel costs | | 4,818 |
| | — |
|
| Fuel inventory - at average cost | | 1,841 |
| | 1,912 |
|
| Materials and supplies - at average cost | | 8,416 |
| | 13,244 |
|
| Prepayments and other | | 10,966 |
| | 10,263 |
|
| TOTAL | | 212,315 |
| | 198,074 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property at cost (less accumulated depreciation) | | 1,016 |
| | 1,016 |
|
| Storm reserve escrow account | | 81,437 |
| | 81,002 |
|
| Other | | 7,160 |
| | 3 |
|
| TOTAL | | 89,613 |
| | 82,021 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 1,258,934 |
| | 1,051,239 |
|
| Natural gas | | 240,408 |
| | 232,780 |
|
| Construction work in progress | | 24,975 |
| | 29,027 |
|
| TOTAL UTILITY PLANT | | 1,524,317 |
| | 1,313,046 |
|
| Less - accumulated depreciation and amortization | | 604,825 |
| | 648,081 |
|
| UTILITY PLANT - NET | | 919,492 |
| | 664,965 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Deferred fuel costs | | 4,080 |
| | 4,080 |
|
| Other regulatory assets (includes securitization property of $82,272 as of December 31, 2016 and $91,599 as of December 31, 2015) | | 268,106 |
| | 265,322 |
|
| Other | | 963 |
| | 682 |
|
| TOTAL | | 273,149 |
| | 270,084 |
|
| | | | | |
| TOTAL ASSETS | |
| $1,494,569 |
| |
| $1,215,144 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| ASSETS |
| | | |
| | | December 31, |
| | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | |
| CURRENT ASSETS | | | | |
| Cash and cash equivalents | | | | |
| Cash | |
| $1,068 |
| |
| $1,006 |
|
| Temporary cash investments | | 87,808 |
| | 41,383 |
|
| Total cash and cash equivalents | | 88,876 |
| | 42,389 |
|
| Securitization recovery trust account | | 4,620 |
| | — |
|
| Accounts receivable: | | |
| | |
|
| Customer | | 34,627 |
| | 38,500 |
|
| Allowance for doubtful accounts | | (268 | ) | | (262 | ) |
| Associated companies | | 23,248 |
| | 11,693 |
|
| Other | | 3,753 |
| | 3,223 |
|
| Accrued unbilled revenues | | 17,799 |
| | 18,531 |
|
| Total accounts receivable | | 79,159 |
| | 71,685 |
|
| Accumulated deferred income taxes | | — |
| | 8,562 |
|
| Fuel inventory - at average cost | | 1,912 |
| | 3,016 |
|
| Materials and supplies - at average cost | | 13,244 |
| | 12,650 |
|
| Prepayments and other | | 10,263 |
| | 7,092 |
|
| TOTAL | | 198,074 |
| | 145,394 |
|
| | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
|
| Non-utility property at cost (less accumulated depreciation) | | 1,016 |
| | 1,016 |
|
| Storm reserve escrow account | | 81,002 |
| | 18,038 |
|
| TOTAL | | 82,018 |
| | 19,054 |
|
| | | | | |
| UTILITY PLANT | | |
| | |
|
| Electric | | 1,051,239 |
| | 1,028,251 |
|
| Natural gas | | 232,780 |
| | 228,979 |
|
| Construction work in progress | | 29,027 |
| | 18,866 |
|
| TOTAL UTILITY PLANT | | 1,313,046 |
| | 1,276,096 |
|
| Less - accumulated depreciation and amortization | | 648,081 |
| | 625,222 |
|
| UTILITY PLANT - NET | | 664,965 |
| | 650,874 |
|
| | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
|
| Regulatory assets: | | |
| | |
|
| Deferred fuel costs | | 4,080 |
| | 4,080 |
|
| Other regulatory assets (includes securitization property of $91,599 as of December 31, 2015) | | 265,322 |
| | 194,851 |
|
| Other | | 685 |
| | 663 |
|
| TOTAL | | 270,087 |
| | 199,594 |
|
| | | | | |
| TOTAL ASSETS | |
| $1,215,144 |
| |
| $1,014,916 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | December 31, |
| | | 2016 | | 2015 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
Payable due to Entergy Louisiana
| |
| $2,104 |
| |
| $4,973 |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 39,260 |
| | 37,467 |
|
| Other | | 35,920 |
| | 21,471 |
|
| Customer deposits | | 28,667 |
| | 28,392 |
|
| Interest accrued | | 5,443 |
| | 4,909 |
|
| Deferred fuel costs | | — |
| | 29,021 |
|
| Other | | 11,415 |
| | 6,216 |
|
| TOTAL CURRENT LIABILITIES | | 122,809 |
| | 132,449 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 334,953 |
| | 214,061 |
|
| Accumulated deferred investment tax credits | | 622 |
| | 753 |
|
| Regulatory liability for income taxes - net | | 9,074 |
| | 13,199 |
|
| Asset retirement cost liabilities | | 2,875 |
| | 2,687 |
|
| Accumulated provisions | | 88,513 |
| | 84,187 |
|
| Pension and other postretirement liabilities | | 36,750 |
| | 43,609 |
|
| Long-term debt (includes includes securitization bonds of $84,776 as of December 31, 2016 and $95,867 as of December 31, 2015) | | 428,467 |
| | 317,380 |
|
Long-term payable due to Entergy Louisiana
| | 18,423 |
| | 20,527 |
|
| Gas system rebuild insurance proceeds | | 447 |
| | 12,788 |
|
| Other | | 4,910 |
| | 3,692 |
|
| TOTAL NON-CURRENT LIABILITIES | | 925,034 |
| | 712,883 |
|
| | | | | |
| 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 2016 and 2015 | | 33,744 |
| | 33,744 |
|
| Paid-in capital | | 171,544 |
| | 123,794 |
|
| Retained earnings | | 221,658 |
| | 192,494 |
|
| TOTAL | | 426,946 |
| | 350,032 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $1,494,569 |
| |
| $1,215,144 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| CONSOLIDATED BALANCE SHEETS |
| LIABILITIES AND EQUITY |
| | | December 31, |
| | | 2015 | | 2014 |
| | | (In Thousands) |
| | | | | |
| CURRENT LIABILITIES | | | | |
Payable due to Entergy Louisiana
| |
| $4,973 |
| |
| $— |
|
| Accounts payable: | | |
| | |
|
| Associated companies | | 37,467 |
| | 33,170 |
|
| Other | | 21,471 |
| | 22,435 |
|
| Customer deposits | | 28,392 |
| | 26,848 |
|
| Interest accrued | | 4,909 |
| | 3,639 |
|
| Deferred fuel costs | | 29,021 |
| | 29,203 |
|
| Other | | 6,216 |
| | 6,994 |
|
| TOTAL CURRENT LIABILITIES | | 132,449 |
| | 122,289 |
|
| | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 214,061 |
| | 199,241 |
|
| Accumulated deferred investment tax credits | | 753 |
| | 904 |
|
| Regulatory liability for income taxes - net | | 13,199 |
| | 19,275 |
|
| Asset retirement cost liabilities | | 2,687 |
| | 2,511 |
|
| Accumulated provisions | | 84,187 |
| | 25,877 |
|
| Pension and other postretirement liabilities | | 43,609 |
| | 62,440 |
|
| Long-term debt (includes includes securitization bonds of $95,867 as of December 31, 2015) | | 317,380 |
| | 221,184 |
|
| Gas system rebuild insurance proceeds | | 12,788 |
| | 23,218 |
|
Long-term payable due to Entergy Louisiana
| | 20,527 |
| | 82,316 |
|
| Other | | 3,692 |
| | 7,856 |
|
| TOTAL NON-CURRENT LIABILITIES | | 712,883 |
| | 644,822 |
|
| | | | | |
| 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 2015 and 2014 | | 33,744 |
| | 33,744 |
|
| Paid-in capital | | 123,794 |
| | 36,294 |
|
| Retained earnings | | 192,494 |
| | 157,987 |
|
| TOTAL | | 350,032 |
| | 228,025 |
|
| | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $1,215,144 |
| |
| $1,014,916 |
|
| | | | | |
| See Notes to Financial Statements. | | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2013 |
| $33,744 |
| |
| $36,294 |
| |
| $136,245 |
| |
| $206,283 |
|
| Net income | — |
| | — |
| | 31,030 |
| | 31,030 |
|
Net income attributable to Entergy Louisiana
| — |
| | — |
| | (2,323 | ) | | (2,323 | ) |
| Common stock dividends | — |
| | — |
| | (6,000 | ) | | (6,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2014 |
| $33,744 |
| |
| $36,294 |
| |
| $157,987 |
| |
| $228,025 |
|
| Net income | — |
| | — |
| | 44,925 |
| | 44,925 |
|
Net income attributable to Entergy Louisiana
| — |
| | — |
| | (2,203 | ) | | (2,203 | ) |
| Capital contributions from parent | — |
| | 87,500 |
| | — |
| | 87,500 |
|
| Common stock dividends | — |
| | — |
| | (7,250 | ) | | (7,250 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2015 |
| $33,744 |
| |
| $123,794 |
| |
| $192,494 |
| |
| $350,032 |
|
| Net income | — |
| | — |
| | 48,849 |
| | 48,849 |
|
| Capital contributions from parent | — |
| | 47,750 |
| | — |
| | 47,750 |
|
| Common stock dividends | — |
| | — |
| | (18,720 | ) | | (18,720 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2016 |
| $33,744 |
| |
| $171,544 |
| |
| $221,658 |
| |
| $426,946 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC AND SUBSIDIARIES |
| CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY |
| For the Years Ended December 31, 2015, 2014, and 2013 |
| | | | |
| | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) |
| | | | | | | | |
| Balance at December 31, 2012 |
| $33,744 |
| |
| $36,294 |
| |
| $125,527 |
| |
| $195,565 |
|
| Net income | — |
| | — |
| | 12,608 |
| | 12,608 |
|
Net income attributable to Entergy Louisiana
| — |
| | — |
| | (925 | ) | | (925 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2013 |
| $33,744 |
| |
| $36,294 |
| |
| $136,245 |
| |
| $206,283 |
|
| Net income | — |
| | — |
| | 31,030 |
| | 31,030 |
|
Net income attributable to Entergy Louisiana
| — |
| | — |
| | (2,323 | ) | | (2,323 | ) |
| Common stock dividends | — |
| | — |
| | (6,000 | ) | | (6,000 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2014 |
| $33,744 |
| |
| $36,294 |
| |
| $157,987 |
| |
| $228,025 |
|
| Net income | — |
| | — |
| | 44,925 |
| | 44,925 |
|
| Net income attributable to Entergy Louisiana | — |
| | — |
| | (2,203 | ) | | (2,203 | ) |
| Capital contributions from parent | — |
| | 87,500 |
| | — |
| | 87,500 |
|
| Common stock dividends | — |
| | — |
| | (7,250 | ) | | (7,250 | ) |
| Preferred stock dividends | — |
| | — |
| | (965 | ) | | (965 | ) |
| Balance at December 31, 2015 |
| $33,744 |
| |
| $123,794 |
| |
| $192,494 |
| |
| $350,032 |
|
| | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON |
| | | | | | | | | | |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $665,463 |
| |
| $671,446 |
| |
| $735,192 |
| |
| $659,746 |
| |
| $605,014 |
|
| Net income |
| $48,849 |
| |
| $44,925 |
| |
| $31,030 |
| |
| $12,608 |
| |
| $19,878 |
|
| Total assets |
| $1,494,569 |
| |
| $1,215,144 |
| |
| $1,014,916 |
| |
| $964,482 |
| |
| $953,308 |
|
| Long-term obligations (a) |
| $466,670 |
| |
| $357,687 |
| |
| $323,280 |
| |
| $318,034 |
| |
| $215,619 |
|
| | | | | | | | | | |
(a) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.
|
| | | | | | | | | | |
| | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $231 |
| |
| $220 |
| |
| $230 |
| |
| $221 |
| |
| $195 |
|
| Commercial | 206 |
| | 186 |
| | 196 |
| | 194 |
| | 174 |
|
| Industrial | 33 |
| | 30 |
| | 33 |
| | 35 |
| | 31 |
|
| Governmental | 69 |
| | 64 |
| | 67 |
| | 69 |
| | 65 |
|
| Total retail | 539 |
| | 500 |
| | 526 |
| | 519 |
| | 465 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 30 |
| | 66 |
| | 78 |
| | 27 |
| | 45 |
|
| Non-associated companies | 3 |
| | — |
| | 4 |
| | — |
| | — |
|
| Other | 15 |
| | 18 |
| | 17 |
| | 19 |
| | 13 |
|
| Total |
| $587 |
| |
| $584 |
| |
| $625 |
| |
| $565 |
| |
| $523 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 2,231 |
| | 2,301 |
| | 2,262 |
| | 2,152 |
| | 2,060 |
|
| Commercial | 2,268 |
| | 2,257 |
| | 2,181 |
| | 2,130 |
| | 2,105 |
|
| Industrial | 441 |
| | 463 |
| | 455 |
| | 484 |
| | 487 |
|
| Governmental | 794 |
| | 825 |
| | 783 |
| | 778 |
| | 806 |
|
| Total retail | 5,734 |
| | 5,846 |
| | 5,681 |
| | 5,544 |
| | 5,458 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,071 |
| | 1,644 |
| | 1,379 |
| | 517 |
| | 1,004 |
|
| Non-associated companies | 141 |
| | 11 |
| | 18 |
| | 14 |
| | 9 |
|
| Total | 6,946 |
| | 7,501 |
| | 7,078 |
| | 6,075 |
| | 6,471 |
|
| | | | | | | | | | |
| | | | | | | | | | |
|
|
| | | | | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON (a) |
| | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 |
| | (In Thousands) |
| | | | | | | | | | |
| Operating revenues |
| $671,446 |
| |
| $735,192 |
| |
| $659,746 |
| |
| $605,014 |
| |
| $672,659 |
|
| Net Income |
| $44,925 |
| |
| $31,030 |
| |
| $12,608 |
| |
| $19,878 |
| |
| $37,149 |
|
| Total assets |
| $1,215,144 |
| |
| $1,014,916 |
| |
| $964,482 |
| |
| $953,308 |
| |
| $871,541 |
|
| Long-term obligations (b) |
| $357,687 |
| |
| $323,280 |
| |
| $318,034 |
| |
| $215,619 |
| |
| $248,512 |
|
| | | | | | | | | | |
| | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 |
| | (Dollars In Millions) |
| | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
|
| Residential |
| $220 |
| |
| $230 |
| |
| $221 |
| |
| $195 |
| |
| $201 |
|
| Commercial | 186 |
| | 196 |
| | 194 |
| | 174 |
| | 165 |
|
| Industrial | 30 |
| | 33 |
| | 35 |
| | 31 |
| | 30 |
|
| Governmental | 64 |
| | 67 |
| | 69 |
| | 65 |
| | 61 |
|
| Total retail | 500 |
| | 526 |
| | 519 |
| | 465 |
| | 457 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 66 |
| | 78 |
| | 27 |
| | 45 |
| | 96 |
|
| Non-associated companies | — |
| | 4 |
| | — |
| | — |
| | 1 |
|
| Other | 18 |
| | 17 |
| | 19 |
| | 13 |
| | 18 |
|
| Total |
| $584 |
| |
| $625 |
| |
| $565 |
| |
| $523 |
| |
| $572 |
|
| | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
|
| Residential | 2,301 |
| | 2,262 |
| | 2,152 |
| | 2,060 |
| | 2,196 |
|
| Commercial | 2,257 |
| | 2,181 |
| | 2,130 |
| | 2,105 |
| | 2,083 |
|
| Industrial | 463 |
| | 455 |
| | 484 |
| | 487 |
| | 501 |
|
| Governmental | 825 |
| | 783 |
| | 778 |
| | 806 |
| | 816 |
|
| Total retail | 5,846 |
| | 5,681 |
| | 5,544 |
| | 5,458 |
| | 5,596 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
|
| Associated companies | 1,644 |
| | 1,379 |
| | 517 |
| | 1,004 |
| | 1,194 |
|
| Non-associated companies | 11 |
| | 18 |
| | 14 |
| | 9 |
| | 21 |
|
| Total | 7,501 |
| | 7,078 |
| | 6,075 |
| | 6,471 |
| | 6,811 |
|
| | | | | | | | | | |
| | | | | | | | | | |
|
| (a) Amounts have been retrospectively adjusted to reflect the effects of the transfer of the Algiers assets in all periods presented. See Note 1 to the financial statements for a discussion of the Algiers asset transfer. |
(b) Includes long-term debt (including the long-term payable to Entergy Louisiana and excluding currently maturing debt) and preferred stock without sinking fund.
|
ENTERGY TEXAS, INC. AND SUBSIDIARIES
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
Results of Operations
Net Income
2016 Compared to 2015
Net income increased $37.9 million primarily due to lower other operation and maintenance expenses, the asset write-off of its receivable associated with the Spindletop gas storage facility in 2015, and higher net revenue.
2015 Compared to 2014
Net income decreased $5.2 million primarily due to the asset write-off of its receivable associated with the Spindletop gas storage facility and higher other operation and maintenance expenses, partially offset by higher net revenue and a lower effective tax rate.
2014Net Revenue
2016 Compared to 20132015
Net income increased $16.9 millionrevenue 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 2016 to 2015.
|
| | | |
| Amount |
| (In Millions) |
| |
|
| 2015 net revenue |
| $637.2 |
|
| Reserve equalization | 14.3 |
|
| Purchased power capacity | 12.4 |
|
| Transmission revenue | 7.0 |
|
| Retail electric price | 5.4 |
|
| Net wholesale | (27.8 | ) |
| Other | (4.3 | ) |
| 2016 net revenue |
| $644.2 |
|
The reserve equalization variance is primarily due to higher neta reduction in reserve equalization expense primarily due to changes in the Entergy System generation mix compared to the same period in 2015 as a result of the execution of a new purchased power agreement and Entergy Mississippi’s exit from the System Agreement, each in November 2015, and Entergy Texas’s exit from the System Agreement in August 2016. See Note 2 to the financial statements for a discussion of the System Agreement.
The purchased power capacity variance is primarily due to decreased expenses due to the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016, as well as capacity cost changes for ongoing purchased power capacity contracts.
The transmission revenue variance is primarily due to an increase in Attachment O rates charged by MISO to transmission customers and lower other operationa settlement of Attachment O rates previously billed to transmission customers by MISO.
Entergy Texas, Inc. and maintenance expenses,Subsidiaries
Management’s Financial Discussion and Analysis
The retail electric price variance is primarily due to the implementation of the transmission cost recovery factor rider, as approved by the PUCT and implemented in September 2016, and the increase in the distribution cost recovery rider, as approved by the PUCT and implemented in January 2016. This increase was partially offset by a higher effective income tax rate, higher taxes other than income taxes,decrease in energy efficiency revenues. See Note 2 to the financial statements for further discussion of the transmission cost recovery factor rider and higher depreciation and amortization expenses.distribution cost recovery factor rider filings.
Net RevenueThe net wholesale revenue variance is primarily due to lower capacity revenues resulting from the termination of the purchased power agreements between Entergy Louisiana and Entergy Texas in August 2016.
2015 Compared to 2014
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 2015 to 2014.
|
| | | |
| | Amount |
| | (In Millions) |
| | |
|
| 2014 net revenue |
| $611.7 |
|
| Volume/weather | 17.1 |
|
| Retail electric price | 11.4 |
|
| Transmission revenue | 4.0 |
|
| Purchased power capacity | (5.6 | ) |
| Other | (1.4 | ) |
| 2015 net revenue |
| $637.2 |
|
The volume/weather variance is primarily due to an increase in residential and commercial sales as a result of a 2% increase in the average number of customers, partially offset by a decrease in sales to industrial customers and the effect of less favorable weather on residential sales. The decrease in industrial sales is primarily due to extended seasonal outages for existing large refinery customers, partially offset by new customers in the transportation industry.
The retail electric price variance is primarily due to an annual base rate increase of $18.5 million, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case, the implementation of the distribution cost recovery rider, as approved by the PUCT, and an increase in the energy efficiency rider, as approved by the PUCT, each effective January 2015. Energy efficiency revenues are largely offset by costs included in other operation and maintenance expenses and have a minimal effect on net income. See Note 2 to the financial statements for further discussion of the rate case.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The transmission revenue variance is primarily due to an increase in the amount of transmission revenues allocated by MISO.
The purchased power capacity variance is primarily due to increased expenses due to contract changes and price changes for ongoing purchased power capacity.
2014 Compared to 2013
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 2014 to 2013.
|
| | | |
| Amount |
| (In Millions) |
| |
|
2013 net revenue |
| $586.5 |
|
Purchased power capacity | 37.5 |
|
Retail electric price | 17.3 |
|
Volume/weather | 11.6 |
|
Transmission revenue | (7.6 | ) |
Reserve equalization | (18.0 | ) |
Net wholesale revenue | (21.0 | ) |
Other | 5.4 |
|
2014 net revenue |
| $611.7 |
|
The purchased power capacity variance is primarily due to a decrease in expenses due to contract changes.
The retail electric price variance is primarily due to an annual base rate increase of $18.5 million, effective April 2014, as a result of the PUCT’s order in the September 2013 rate case. See Note 2 to the financial statements for further discussion of the PUCT rate order.
The volume/weather variance is primarily due to an increase of 884 GWh, or 5%, in billed electricity usage, including the effect of more favorable weather on residential sales and increased industrial usage primarily in the petroleum industry as a result of expansions.
The transmission revenue variance is primarily due to changes as a result of the participation in the MISO RTO in 2014.
The reserve equalization variance is primarily due to an increase in reserve equalization expense as compared to the same period in 2013 primarily due to the changes in the Entergy System generation mix compared to the same period in 2013 as a result of the Entergy Arkansas’s exit from the System Agreement in December 2013.
The net wholesale revenue variance is primarily due to a wholesale customer contract termination in December 2013.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Other Income Statement Variances
2016 Compared to 2015
Other operation and maintenance expenses decreased primarily due to:
a decrease of $11.2 million in fossil-fueled generation expenses primarily due to an overall lower scope of work performed in 2016 as compared to 2015;
a decrease of $7 million in transmission expenses primarily due to lower transmission equalization expenses, as allocated under the System Agreement, as compared to the same period in 2015 as a result of Entergy Mississippi’s exit from the System Agreement in November 2015 and Entergy Texas’s exit from the System Agreement in August 2016;
a decrease of $5.7 million in compensation and benefits costs primarily due to a decrease in net periodic pension and other postretirement benefits costs as a result of an increase in the discount rate used to value the benefit liabilities and a refinement in the approach used to estimate the service cost and interest cost components of pension and other postretirement costs. See “Critical Accounting Estimates - Qualified Pension and Other Postretirement Benefits” below and Note 11 to the financial statements for further discussion of pension and other postretirement benefit costs;
the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its certificate of convenience and necessity filing; and
a decrease of $4.2 million in energy efficiency costs.
The asset write-off variance is due to the $23.5 million ($15.3 million net-of-tax) write-off recorded in 2015 of the receivable associated with the Spindletop gas storage facility. See Note 2 to the financial statements for discussion of the write-off.
2015 Compared to 2014
Other operation and maintenance expenses increased primarily due to:
an increase of $7.5 million in transmission expenses primarily due to an increase in the amount of transmission costs allocated by MISO;
a net increase of $6.4 million in energy efficiency costs for fixed costs collected from customers. These costs are recovered through the energy efficiency rider and have a minimal effect on net income;customers; and
the write-off in the third quarter 2015 of $4.3 million of rate case expenses and acquisition costs related to the proposed Union Power Station acquisition upon Entergy Texas’s withdrawal of its 2015 rate case and dismissal of its Certificatecertificate of Convenienceconvenience and Necessitynecessity filing. See Note 2 to the financial statements for discussion of these proceedings.
The asset write-off variance is due to the $23.5 million ($15.3 million net-of-tax) write-off recorded in 2015 of the receivable associated with the Spindletop gas storage facility. See Note 2 to the financial statements for discussion of the write-off.
2014 Compared to 2013
Other operation and maintenance expenses decreased primarily due to:
a decrease of $14.9 million in compensation and benefit costs primarily due to an increase in the discount rates used to determine net periodic pension and other postretirement benefit costs, other postretirement benefit plan design changes, fewer employees, and a settlement charge in 2013 related to the payment of lump sum benefits out of the non-qualified pension plan. See “Critical Accounting Estimates”belowand Note 11 to the financial statements for further discussion of pension and other postretirement benefits costs;
a decrease of $7.4 million resulting from costs incurred in 2013 related to the now-terminated plan to spin off and merge the Utility’s transmission business; and
a decrease of $7.1 million resulting from implementation costs, severance costs, and curtailment and special termination benefits in 2013 related to the human capital management strategic imperative. See the “Human Capital Management Strategic Imperative” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
The decrease was partially offset by an increase of $5.9 million primarily due to administration fees in 2014 related to participation in the MISO RTO.
Taxes other than income taxes increased primarily due to a reduction in the provision recorded for sales and use taxes in 2013, an increase in local franchise taxes, and an increase in ad valorem taxes.
Depreciation and amortization expenses increased primarily due to additions to plant in service.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014 and 2013 were 37.0%, 34.9%, 39.9%, and 34.2%39.9%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, 2014, and 20132014 were as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $30,441 |
| |
| $46,488 |
| |
| $60,236 |
|
| $2,182 |
| |
| $30,441 |
| |
| $46,488 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | |
| | |
| | |
| |
| | |
| | |
|
| Operating activities | 284,268 |
| | 315,164 |
| | 237,054 |
| 306,601 |
| | 284,268 |
| | 315,164 |
|
| Investing activities | (315,293 | ) | | (186,540 | ) | | (164,309 | ) | (330,191 | ) | | (315,293 | ) | | (186,540 | ) |
| Financing activities | 2,766 |
| | (144,671 | ) | | (86,493 | ) | 27,589 |
| | 2,766 |
| | (144,671 | ) |
| Net decrease in cash and cash equivalents | (28,259 | ) | | (16,047 | ) | | (13,748 | ) | |
| Net increase (decrease) in cash and cash equivalents | | 3,999 |
| | (28,259 | ) | | (16,047 | ) |
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $2,182 |
| |
| $30,441 |
| |
| $46,488 |
|
| $6,181 |
| |
| $2,182 |
| |
| $30,441 |
|
Operating Activities
Net cash flow provided by operating activities increased $22.3 million in 2016 primarily due to increased net income and a decrease of $31.8 million in income tax payments in 2016. Entergy Texas had income tax payments in 2016 and 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2016 resulted primarily from adjustments associated with the settlement of the 2010-2011 IRS audit; whereas, the income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences. See Note 3 to the financial statements for a discussion of the income tax audit. The increase was partially offset by an increase of $5.2 million in interest paid in 2016 due to the issuance of $125 million of 2.55% Series first mortgage bonds in March 2016 and the timing of collections from customers.
Net cash flow provided by operating activities decreased $30.9 million in 2015 primarily due to:
income tax payments of $60.4 million in 2015. Entergy Texas had income tax payments in 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2015 resulted primarily from the results of operations and the reversal of taxable temporary differences; and
a net decrease of $24 million related to the System Agreement bandwidth remedy payments in 2014. In the second quarter 2014, Entergy Texas received total payments of $48.6 million as a result of the compliance filing pursuant to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period, of which $24.6 million was refunded to Entergy Texas customers as of December 31, 2014.
The decrease was partially offset by an increase indue to the timing of recovery of fuel and purchased power costs.
Investing Activities
Net cash flow provided by operatingused in investing activities increased $78.1$14.9 million in 20142016 primarily due to:
$86.1to increases of $27.7 million in transmission construction expenditures and $11.7 million in distribution construction expenditures primarily due to a greater scope of fuel cost refundsprojects in 2013;
System Agreement bandwidth remedy payments of $48.6 million received in the second quarter 20142016 as a result of the compliance filing pursuantcompared to the FERC’s February 2014 orders related to the bandwidth payments/receipts for the June - December 2005 period. Entergy Texas received approval to apply a portion of the payments to the under-collected fuel balance. The remaining balance of $24.6 million was refunded to Entergy Texas customers as of December 31, 2014. See Note 2 to the financial statements for a discussion of fuel cost refunds and the System Agreement proceedings; and
the timing of collections from customers.
same period in 2015. The increase was partially offset by:by a $21.4 million decrease in fossil-fueled generation construction expenditures primarily due to a decreased scope of work performed during plant outages in 2016 as compared to the same period in 2015.
a decrease of $54.8 million in income tax refunds in 2014 compared to 2013. Entergy Texas had income tax refunds in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The refunds in 2013 resulted from the utilization of Entergy Texas’s taxable losses against taxable income of other members of the Entergy consolidated group; and
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
an increase of $10.2 million in pension contributions in 2014. See “Critical Accounting Estimates” below and Note 11 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.
Investing Activities
Net cash flow used in investing activities increased $128.8 million in 2015 primarily due to:
an increase in transmission construction expenditures primarily due to a greater scope of projects in 2015;
an increase in information technology capital expenditures due to various technology projects and upgrades in 2015; and
an increase in fossil-fueled generation construction expenditures primarily due to Lewis Creek dam repairs in 2015 and a greater scope of work done during outages in 2015.
Financing Activities
Net cash used in investingflow provided by financing activities increased $22.2$24.8 million in 20142016 primarily due to increasesthe retirement of $200 million of 3.6% Series first mortgage bonds in transmission construction expendituresJune 2015 and fossil-fueled generation construction expenditures due to a greater scopethe issuance of projects$125 million of 2.55% Series first mortgage bonds in 2014March 2016, partially offset by the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015 and money pool activity.
Decreases in Entergy Texas’s receivable frompayable to the money pool are a sourceuse of cash flow, and Entergy Texas’s receivable frompayable to the money pool decreased by $6$22.1 million in 20142016 compared to decreasingincreasing by $12.9$22.1 million in 2013.2015. The money pool is an inter-company borrowing arrangement designed to reduce Entergy’sthe Utility subsidiaries’ need for external short-term borrowings.
Financing Activities
Entergy Texas’s financing activities provided $2.8 million of cash in 2015 compared to using $144.7 million of cash in 2014 primarily due to the following activity:
the issuance of $250 million of 5.15% Series first mortgage bonds in May 2015;
the retirement, prior to maturity, of $150 million of 7.875% Series first mortgage bonds in June 2014;
$70 million in common stock dividends paid in 2014;2014. Entergy Texas did not pay dividends to its parent in 2015 primarily because of lower operating cash flows and higher capital expenditures, each discussed above; and
money pool activity.
These activities were partially offset by the retirement of $200 million of 3.6% Series first mortgage bonds in June 2015 and the issuance of $135 million of 5.625% Series first mortgage bonds in May 2014.
Increases in Entergy Texas’s payable to the money pool are a source of cash flow, and Entergy Texas’s payable to the money pool increased by $22.1 million in 2015.
Net cash flow used in financing activities increased $58.2 million in 2014 primarily due to the retirement of $150 million of 7.875% Series first mortgage bonds in June 2014 and an increase of $45 million in common stock dividends paid, partially offset by the issuance of $135 million of 5.625% Series first mortgage bonds in May 2014. See Note 5 to the financial statements for more details on long-term debt.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Capital Structure
Entergy Texas’s capitalization is balanced between equity and debt, as shown in the following table. The decrease in the debt to capital ratio for Entergy Texas is primarily due to an increase in retained earnings.
| | | | December 31,
2015 | | December 31,
2014 | December 31,
2016 | | December 31,
2015 |
| Debt to capital | 60.2 | % | | 62.2 | % | 58.5 | % | | 60.2 | % |
| Effect of excluding the securitization bonds | (10.4 | %) | | (11.8 | %) | (8.3 | %) | | (10.4 | %) |
| Debt to capital, excluding securitization bonds (a) | 49.8 | % | | 50.4 | % | 50.2 | % | | 49.8 | % |
| Effect of subtracting cash | — | % | | (0.8 | %) | (0.1 | %) | | — | % |
| Net debt to net capital, excluding securitization bonds (a) | 49.8 | % | | 49.6 | % | 50.1 | % | | 49.8 | % |
|
| |
| (a) | 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 long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. Entergy Texas uses the debt to capital ratios excluding securitization bonds in analyzing its financial
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
condition and believes they provide useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because the securitization bonds are non-recourse to Entergy Texas, as more fully described in Note 5 to the financial statements. Entergy Texas also uses the net debt to net capital ratio excluding securitization bonds in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating Entergy Texas’s financial condition because net debt indicates Entergy Texas’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
Entergy Texas seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, Entergy Texas may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure. In addition, in certain infrequent circumstances, such as large transactions that would materially alter the capital structure if financed entirely with debt and reducing dividends, Entergy Texas may receive equity contributions to maintain the targeted capital structure.
Uses of Capital
Entergy Texas requires capital resources for:
construction and other capital investments;
debt 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 Texas’s planned construction and other capital investments.
| | | | 2016 | | 2017 | | 2018 | 2017 | | 2018 | | 2019 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $40 |
| |
| $40 |
| |
| $230 |
|
| $85 |
| |
| $180 |
| |
| $375 |
|
| Transmission | 105 |
| | 130 |
| | 220 |
| 115 |
| | 180 |
| | 210 |
|
| Distribution | 110 |
| | 110 |
| | 120 |
| 100 |
| | 125 |
| | 135 |
|
| Other | 35 |
| | 15 |
| | 10 |
| 50 |
| | 30 |
| | 15 |
|
| Total |
| $290 |
| |
| $295 |
| |
| $580 |
|
| $350 |
| |
| $515 |
| |
| $735 |
|
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Following are the amounts of Entergy Texas’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total | 2017 | | 2018-2019 | | 2020-2021 | | After 2021 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $83 |
| |
| $214 |
| |
| $703 |
| |
| $1,474 |
| |
| $2,474 |
|
| $150 |
| |
| $775 |
| |
| $416 |
| |
| $1,068 |
| |
| $2,409 |
|
| Operating leases (b) |
| $6 |
| |
| $9 |
| |
| $5 |
| |
| $1 |
| |
| $21 |
|
| $5 |
| |
| $9 |
| |
| $4 |
| |
| $2 |
| |
| $20 |
|
| Purchase obligations (c) |
| $307 |
| |
| $595 |
| |
| $602 |
| |
| $237 |
| |
| $1,741 |
|
| $269 |
| |
| $558 |
| |
| $544 |
| |
| $811 |
| |
| $2,182 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | Does not include power purchase agreements that are accounted for as leases that are included in purchase obligations. |
| |
| (c) | 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 $15.8$17 million to its qualified pension plans and approximately $3.2 million to other postretirement health care and life insurance plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017. 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 Texas has $13.2$15.6 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.
In addition to routine capital spending to maintain operations, the planned capital investment estimate for Entergy Texas includes specific investments such as environmental compliance spending;the Montgomery County Power Station discussed below; transmission projects to enhance reliability, reduce congestion, and enable economic growth; distribution spending to maintainenhance reliability and improve service to customers, including initial investment to support smart meter deployment; resource planning, including potential generation projects;advanced metering; system improvements; and other investments. Estimated capital expenditures are subject to periodic review and modification and may vary based on the ongoing effects of regulatory constraints and requirements, environmental compliance, business opportunities, market volatility, economic trends, business restructuring, changes in project plans, and the ability to access capital. Management provides more information on long-term debt in Note 5 to the financial statements.
As a wholly-owned subsidiary,discussed above in “Capital Structure,” Entergy Texas paysroutinely evaluates its ability to pay dividends to Entergy Corporation from its earnings at a percentage determined monthly.earnings.
Sources of Capital
Entergy Texas’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt or preferred stock issuances; and
bank financing under new or existing facilities.
Entergy Texas may refinance, redeem, or otherwise retire debt prior to maturity, to the extent market conditions and interest and dividend rates are favorable.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
All debt and common and preferred stock issuances by Entergy Texas require prior regulatory approval. Debt issuances are also subject to issuance tests set forth in its bond indenture and other agreements. Entergy Texas has sufficient capacity under these tests to meet its foreseeable capital needs.
Entergy Texas’s receivables from or (payables to) the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| ($22,068) | | $306 | | $6,287 | | $19,175 |
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| $681 | | ($22,068) | | $306 | | $6,287 |
See Note 4 to the financial statements for a description of the money pool.
Entergy Texas has a credit facility in the amount of $150 million scheduled to expire in August 2020.2021. The credit facility allows Entergy Texas to issue letters of credit against 50% of the borrowing capacity of the facility. As of December 31, 2015,2016, there were no cash borrowings and $1.3$4.7 million of letters of credit outstanding under the credit facility. In addition, Entergy Texas is a party to an uncommitted letter of credit facility as a means to post collateral
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
to support its obligations under MISO. As of December 31, 2015,2016, a $9.4$14.7 million letter of credit was outstanding under Entergy Texas’s letter of credit facility. See Note 4 to the financial statements for additional discussion of the credit facilities.
Entergy Texas obtained authorizations from the FERC through October 2017 for short-term borrowings, not to exceed an aggregate amount of $200 million at any time outstanding, and long-term borrowings and security issuances. See Note 4 to the financial statements for further discussion of Entergy Texas’s short-term borrowing limits.
Montgomery County Power Station
In May 2015,October 2016, Entergy Texas issued $250filed an application with the PUCT seeking certification that the public convenience and necessity would be served by the construction of the Montgomery County Power Station, a nominal 993 megawatt combined-cycle generating unit in Montgomery County, Texas on land adjacent to the existing Lewis Creek plant. The current estimated cost of the Montgomery County Power Station is $937 million, including estimated costs of 5.15% Series first mortgage bonds due June 2045. Entergytransmission interconnection and network upgrades and other related costs. The independent monitor, who oversaw the request for proposal process, filed testimony and a report affirming that the Montgomery County Power Station was selected through an objective and fair request for proposal that showed no undue preference to any proposal. Discovery has commenced and a procedural schedule has been established for this proceeding, including an evidentiary hearing in May 2017. A PUCT decision regarding the application is expected by October 2017, pursuant to a Texas usedstatute requiring the proceedsPUCT to pay, at maturity, its $200 millionissue an order regarding a certificate of 3.60% Series first mortgage bonds due June 2015convenience and for general corporate purposes.necessity within 366 days of the filing. Subject to timely approval by the PUCT and receipt of other permits and approvals, commercial operation is estimated to occur by mid-2021.
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
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 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
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 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
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 also filed motions for rehearing of the PUCT’s order. The PUCT subsequently denied rehearing of substantive issues. Several parties, including Entergy Texas, appealed various aspects of the PUCT’s order to the Travis County District Court. A hearing was held in July 2014. In October 2014 the Travis County District Court issued an order upholding the PUCT’s decision except as to the line-loss factor issue referenced above, which was found in favor of Entergy Texas. In November 2014, Entergy Texas and other parties, including the PUCT, appealed the Travis County District Court decision to the Third Court of Appeals. Briefs were filed by the appealing and responding parties in the first half of 2015. Oral argument before the court panel was held in September 2015. TheIn April 2016 the Third Court of Appeals issued its opinion affirming the District Court’s decision on all points. Entergy Texas petitioned the Texas Supreme Court to hear its appeal of the Third Court’s ruling. That petition is currently pending.
2013 Rate Case
In September 2013, Entergy Texas filed a rate case requesting a $38.6 million base rate increase reflecting a 10.4% return on common equity based on an adjusted test year ending March 31, 2013. The rate case also proposed (1) a rough production cost equalization adjustment rider recovering Entergy Texas’s payment to Entergy New Orleans to achieve rough production cost equalization based on calendar year 2012 production costs and (2) a rate case expense rider recovering the cost of the 2013 rate case and certain costs associated with previous rate cases. The rate case filing also included a request to reconcile $0.9 billion of fuel and purchased power costs and fuel revenues covering the period July 2011 through March 2013. The fuel reconciliation also reflects special circumstances fuel cost recovery of approximately $22 million of purchased power capacity costs. In January 2014 the PUCT staff filed direct testimony recommending a retail rate reduction of $0.3 million and a 9.2% return on common equity. In March 2014, Entergy Texas filed an Agreed Motion for Interim Rates. The motion explained that the parties to this proceeding have agreed that Entergy Texas should be allowed to implement new rates reflecting an $18.5 million base rate increase, effective for usage on and after April 1, 2014, as well as recovery of charges for rough production cost equalization and rate case expenses. In March 2014 the State Office of Administrative Hearings, the body assigned to hear the case, approved the motion. In April 2014, Entergy Texas filed a unanimous stipulation in this case. Among other things, the stipulation provides for an $18.5 million base rate increase, provides for recovery over three years of the calendar year 2012 rough production cost equalization charges and rate case expenses, and states a 9.8% return on common equity. In addition, the stipulation finalizes the fuel and purchased power reconciliation covering the period July 2011 through March 2013, with the parties stipulating an immaterial fuel disallowance. No special circumstances recovery of purchased power capacity costs was allowed. In April 2014 the State Office of Administrative Hearings remanded the case back to the PUCT for final processing. In May 2014 the PUCT approved the stipulation. No motions for rehearing were filed during the statutory rehearing period.
2015 Rate Case
In June 2015, Entergy Texas filed a rate case that included pro forma adjustments to reflect the proposed acquisition of Union Power Station Power Block 1, which is one of four units that comprise the Union Power Station near El Dorado, Arkansas. Previously in 2015 Entergy Texas made a filing with the PUCT requesting that it grant a certificate of convenience and necessity for the Union acquisition. In July 2015 the PUCT requested briefing on legal and policy issues related to, among other things, the propriety of rate recovery for the Union Power transaction given the uncertainty of the actual closing date of the transaction and the commencement of the rate year, as well as Entergy Texas’s requirement for acceptable rate treatment as a condition to closing the transaction. Also in July 2015, in connection with the requested briefing, the PUCT staff and certain parties filed briefs concluding that Entergy Texas
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
should not be permitted recovery for the Union Power Station purchase in the rate case. Based on the opposition to the acquisition of the power block, Entergy Texas determined it was appropriate to seek to dismiss the Certificate of Convenience and Necessity filing and withdraw the rate case. In July 2015, Entergy Texas filed its notice of withdrawal of its base rate case and the ALJs in the case dismissed the case from the dockets of the State Office of Administrative Hearings and the PUCT. In the third quarter 2015, Entergy Texas wrote off $4.7 million in rate case expenses and acquisition costs related to the proposed Union Power Station acquisition.
Other Filings
In September 2014, Entergy Texas filed for a distribution cost recovery factor (DCRF) rider based on a law that was passed in 2011 allowing for the recovery of increases in capital costs associated with distribution plant. Entergy Texas requested collection of approximately $7 million annually from retail customers. The parties reached a unanimous settlement authorizing recovery of $3.6 million annually commencing with usage on and after January 1, 2015. A State Office of Administrative Hearings ALJ issued an order in December 2014 authorizing this recovery on an interim basis and remanded the case to the PUCT. In February 2015 the PUCT entered a final order, making the settlement final and the interim rates permanent. In September 2015, Entergy Texas filed to amend its distribution cost recovery factor rider. Entergy Texas requested an increase in recovery under the rider of $6.5 million, for a total collection of $10.1 million annually from retail customers. In October 2015 intervenors and PUCT staff filed testimony opposing, in part, Entergy Texas’s request. In November 2015 Entergy Texas and the parties filed an unopposed settlement agreement and supporting documents. The settlement established an annual revenue requirement of $8.65 million for the amended
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
DCRF rider, with the resulting rates effective for usage on and after January 1, 2016. The PUCT approved the settlement agreement in February 2016.
In September 2015, Entergy Texas filed for a transmission cost recovery factor (TCRF) rider requesting a $13 million increase, incremental to base rates. Testimony was filed in November 2015, with the PUCT staff and other parties proposing various disallowances involving, among other things, MISO charges, vegetation management costs, and bad debt expenses that would reduce the requested increase. The largest remaining single disallowance isincrease by approximately $2 million. In addition to those recommended disallowances, a number of parties recommended that Entergy Texas’s request be reduced by an additional $3.4 million which would impose ato account for load growth adjustment on Entergy Texas’s TCRF rider.since base rates were last set. A hearing on the merits was held in December 2015. AIn February 2016 a State Office of Administrative Hearings ALJ issued a proposal for decision recommending that the PUCT disallow approximately $2 million from Entergy Texas’s $13 million request, but recommending that the PUCT not accept the load growth offset. In April 2016 the PUCT voted to allow Entergy Texas’s TCRF rates to become effective as of April 14, 2016 when those rates are finally approved, but did not otherwise address the proposal for decision. In May 2016 the PUCT deferred final consideration of Entergy Texas’s TCRF application and opened the record to consider additional evidence to be provided by Entergy Texas and potentially other parties regarding the rate-making treatment of spare transmission-level transformers that are transferred among the Utility operating companies. In June 2016, the PUCT indicated that it would take up in a future rulemaking project the issue of whether a load growth adjustment should apply to a TCRF. In July 2016 the PUCT issued an order generally accepting the proposal for decision but declining to adjust the TCRF baseline in two instances as recommended by the ALJ, which resulted in a total annual allowance of approximately $10.5 million. The PUCT also ordered its staff and Entergy Texas to track all spare autotransformer transfers going forward so that it could address the appropriate accounting treatment and prudence of such transfers in Entergy Texas’s next base rate case. Entergy Texas implemented the TCRF rider beginning with September 2016 bills.
In September 2016, Entergy Texas filed with the PUCT a request to amend its TCRF rider. The proposed amended TCRF rider is expecteddesigned to collect approximately $29.5 million annually from Entergy Texas’s retail customers. This amount includes the approximately $10.5 million annually that Entergy Texas is currently authorized to collect through the TCRF rider, as discussed above. In September 2016 the PUCT suspended the effective date of the tariff change to March 2017. In December 2016, Entergy Texas and the PUCT reached a settlement agreeing to the amended TCRF annual revenue requirement of $29.5 million. This settlement was developed concurrently with the 2016 fuel reconciliation stipulation and settlement agreement discussed below, and the terms and conditions in first quarter 2016.both settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.
Fuel and Purchased Power Cost Recovery
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 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. Entergy Texas completed this refund to customers in March 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 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 August 2014, Entergy Texas filed an application seeking PUCT approval to implement an interim fuel refund
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
of approximately $24.6 million for over-collected fuel costs incurred during the months of November 2012 through April 2014. This refund resulted from (i) applying $48.6 million in bandwidth remedy payments that Entergy Texas received in May 2014 related to the June - December 2005 period to Entergy Texas’s $8.7 million under-recovered fuel balance as of April 30, 2014 and (ii) netting that fuel balance against the $15.3 million bandwidth remedy payment that Entergy Texas made related to calendar year 2013 production costs. Also in August 2014, Entergy Texas filed an unopposed motion for interim rates to implement these refunds for most customers over a two-month period commencing with September 2014. The PUCT issued its order approving the interim relief in August 2014 and Entergy Texas completed the refunds in October 2014. Parties intervened in this matter, and all parties agreed that the proceeding should be bifurcated such that the proposed interim refund would become final in a separate proceeding, which refund was approved by the PUCT in March 2015. In July 2015 certain parties filed briefs in the open proceeding asserting that Entergy Texas should refund to retail customers an additional $10.9 million in bandwidth remedy payments Entergy
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Texas received related to calendar year 2006 production costs. In October 2015 an ALJ issued a proposal for decision recommending that the additional $10.9 million in bandwidth remedy payments be refunded to retail customers. In January 2016 the PUCT issued its order affirming the ALJ’s recommendation, and Entergy Texas filed a motion for rehearing of the PUCT’s decision, which the PUCT denied. In March 2016, Entergy Texas filed a complaint in Federal District Court for the Western District of Texas and a petition in the Travis County (State) District Court appealing the PUCT’s decision. The federal appeal was heard in December 2016, and the Federal District Court granted Entergy Texas’s requested relief. In January 2017 the PUCT and an intervenor filed petitions for appeal to the U.S. Court of Appeals for the Fifth Circuit of the Federal District Court ruling. The State District Court appeal remains pending. In April 2016, Entergy Texas filed with the PUCT an application to refund to customers approximately $56.2 million. The refund resulted from (i) $41.8 million of fuel cost recovery over-collections through February 2016, (ii) the $10.9 million in bandwidth remedy payments, discussed above, that Entergy Texas received related to calendar year 2006 production costs, and (iii) $3.5 million in bandwidth remedy payments that Entergy Texas received related to 2006-2008 production costs. In June 2016, Entergy Texas filed an unopposed settlement agreement that added additional over-recovered fuel costs for the months of March and April 2016. The settlement resulted in a $68 million refund. The ALJ approved the refund on an interim basis to be made to most customers over a four-month period beginning with the first billing cycle of July 2016. In July 2016 the PUCT issued an order approving the interim refund.
In July 2016, Entergy Texas filed an application to reconcile its fuel and purchased power costs for the period April 1, 2013 through March 31, 2016. Under a recent PUCT rule change, a fuel reconciliation is required to be filed at least once every three years and outside of a base rate case filing. During the reconciliation period, Entergy Texas incurred approximately $1.77 billion in Texas jurisdictional eligible fuel and purchased power expenses, net of certain revenues credited to such expenses and other adjustments. Entergy Texas estimated an over-recovery balance of approximately $19.3 million, including interest, which Entergy Texas requested authority to carry over as the beginning balance for the subsequent reconciliation period beginning Apri1 2016. Entergy Texas also noted, however, that the estimated $19.3 million over collection was being refunded to customers as a portion of the interim fuel refund beginning with the first billing cycle of July 2016, discussed above. Entergy Texas also is requesting a prudence finding for each of the fuel-related contracts and arrangements entered into or modified during the reconciliation period that have not been reviewed by the PUCT in a prior proceeding. In December 2016, Entergy Texas entered into a stipulation and settlement agreement resulting in a $6 million disallowance not associated with any particular issue raised and a refund of the over-recovery balance of $21 million as of November 30, 2016, to customers beginning April 2017 through June 2017. This settlement was developed concurrently with the stipulation and settlement agreement in the 2016 TCRF rider amendment discussed above, and the terms of the two settlements are interdependent. PUCT action on the stipulations and settlement agreements is pending.
At the PUCT’s April 2013 open meeting, the PUCT Commissioners discussed their view that a purchased power capacity rider was good public policy. The PUCT issued an order in May 2013 adopting the rule allowing for a purchased power capacity rider, subject to an offsetting adjustment for load growth. The rule, as adopted, also includes a process for obtaining pre-approval by the PUCT of purchased power agreements. Entergy Texas has not exercised the option to recover its capacity costs under the new rider mechanism, but will continue to evaluate the benefits of utilizing the new rider to recover future capacity costs.
Federal Regulation
See “Entergy’s Integration Into the MISO Regional Transmission Organization” and “System Agreement” in the “Rate, Cost-recovery, and Other Regulation – Federal Regulation” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of these topics.federal regulation.
Nuclear Matters
See the “Nuclear Matters” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of nuclear matters.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
Industrial and Commercial Customers
Entergy 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’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.
Environmental Risks
Entergy 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. and Subsidiaries
Management’s Financial Discussion and Analysis
Critical Accounting Estimates
The preparation of Entergy 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’s financial position or results of operations.
Utility Regulatory Accounting
See “Utility Regulatory Accounting” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
Unbilled Revenue
As discussedSee “Unbilled Revenue” in Note 1 to the financial statements,“Critical Accounting Estimates” section of Entergy Texas records an estimateCorporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of the revenues earned for energy delivered sinceestimates associated with the latest customer billing. Each month the estimated unbilled revenue amounts are recorded as revenueamounts.
Taxation and a receivable,Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the prior month’s estimate is reversed. The difference between the estimate“Critical Accounting Estimates” section of the unbilled receivable at the beginning of the periodEntergy Corporation 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 periodSubsidiaries Management’s Financial Discussion 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.Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
Entergy Texas’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in 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.
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
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 2015 Qualified Pension Cost | | Impact on 2015 Qualified Projected Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Qualified Projected Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,068 | | $11,475 | | (0.25%) | | $768 | |
| $11,375 |
|
| Rate of return on plan assets | | (0.25%) | | $495 | | $— | | (0.25%) | | $823 | | $- |
|
| Rate of increase in compensation | | 0.25% | | $365 | | $1,491 | | 0.25% | | $312 | |
| $1,700 |
|
Entergy Texas, Inc. and Subsidiaries
Management’s Financial Discussion and Analysis
The following chart reflects the sensitivity of postretirement benefit cost and accumulated postretirement benefit obligation changes in certain actuarial assumptions (dollars in thousands).
| | Actuarial Assumption | | Change in Assumption | | Impact on 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $251 | | $3,505 | | (0.25%) | | $251 | | $3,792 |
| Health care cost trend | | 0.25% | | $408 | | $2,529 | | 0.25% | | $482 | | $3,386 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for Entergy Texas in 20152016 was $12.1$5 million. Entergy Texas anticipates 20162017 qualified pension costincome to be $5$3.5 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $3.6 million. Entergy Texas contributed $17.2$15.9 million to its qualified pension plans in 20152016 and estimates 2016-20182017 pension contributions will approximate $43.1be approximately $17 million, including $15.8 million in 2016, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total postretirement health care and life insurance benefit income for Entergy Texas in 20152016 was $3$4.4 million. Entergy Texas expects 20162017 postretirement health care and life insurance benefit income to approximate $4.4$1.8 million. In 2016, Entergy Texas refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $1.1 million. Entergy Texas contributed $2.6$3.2 million to its other postretirement plans in 20152016 and expects 2016-2018estimates 2017 contributions to approximate $4.1 million, includingwill be approximately $3.2 million in 2016.million.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $30.8 million in the qualified pension benefit obligation and $8.2 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $4.3 million and other postretirement cost by approximately $1 million. Pension funding guidelines, as established byIn 2016 the Employee Retirement Income Security Actmortality projection scale was updated to MP-2016, with no change in the base mortality table assumption.
Entergy Texas, Inc. and the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries new mortality assumptions until after 2015, possibly 2016.Subsidiaries
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.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholder of
Entergy Texas, Inc. and Subsidiaries
The Woodlands, Texas
We have audited the accompanying consolidated balance sheets of Entergy Texas, Inc. and Subsidiaries (the “Company”) as of December 31, 20152016 and 2014,2015, and the related consolidated income statements, consolidated statements of cash flows, and consolidated statements of changes in common equity (pages 420419 through 424 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 20152016 and 2014,2015, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $1,707,203 |
| |
| $1,851,982 |
| |
| $1,728,799 |
| |
| $1,615,619 |
| |
| $1,707,203 |
| |
| $1,851,982 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 277,810 |
| | 282,809 |
| | 207,310 |
| | 271,968 |
| | 277,810 |
| | 282,809 |
|
| Purchased power | | 709,947 |
| | 881,438 |
| | 857,512 |
| | 616,597 |
| | 709,947 |
| | 881,438 |
|
| Other operation and maintenance | | 254,731 |
| | 232,955 |
| | 253,786 |
| | 220,566 |
| | 254,731 |
| | 232,955 |
|
| Asset write-off | | 23,472 |
| | — |
| | — |
| | — |
| | 23,472 |
| | — |
|
| Taxes other than income taxes | | 72,945 |
| | 70,439 |
| | 63,823 |
| | 70,973 |
| | 72,945 |
| | 70,439 |
|
| Depreciation and amortization | | 102,410 |
| | 99,609 |
| | 94,744 |
| | 107,026 |
| | 102,410 |
| | 99,609 |
|
| Other regulatory charges - net | | 82,243 |
| | 76,017 |
| | 77,491 |
| | 82,879 |
| | 82,243 |
| | 76,017 |
|
| TOTAL | | 1,523,558 |
| | 1,643,267 |
| | 1,554,666 |
| | 1,370,009 |
| | 1,523,558 |
| | 1,643,267 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 183,645 |
| | 208,715 |
| | 174,133 |
| | 245,610 |
| | 183,645 |
| | 208,715 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 5,678 |
| | 2,959 |
| | 4,647 |
| | 7,617 |
| | 5,678 |
| | 2,959 |
|
| Interest and investment income | | 684 |
| | 1,106 |
| | 1,369 |
| | 987 |
| | 684 |
| | 1,106 |
|
| Miscellaneous - net | | (798 | ) | | (2,345 | ) | | (3,328 | ) | | (746 | ) | | (798 | ) | | (2,345 | ) |
| TOTAL | | 5,564 |
| | 1,720 |
| | 2,688 |
| | 7,858 |
| | 5,564 |
| | 1,720 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 86,024 |
| | 88,049 |
| | 92,156 |
| | 87,776 |
| | 86,024 |
| | 88,049 |
|
| Allowance for borrowed funds used during construction | | (3,690 | ) | | (2,062 | ) | | (3,324 | ) | | (4,943 | ) | | (3,690 | ) | | (2,062 | ) |
| TOTAL | | 82,334 |
| | 85,987 |
| | 88,832 |
| | 82,833 |
| | 82,334 |
| | 85,987 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 106,875 |
| | 124,448 |
| | 87,989 |
| | 170,635 |
| | 106,875 |
| | 124,448 |
|
| | | | | | | | | | | | | |
| Income taxes | | 37,250 |
| | 49,644 |
| | 30,108 |
| | 63,097 |
| | 37,250 |
| | 49,644 |
|
| | | | | | | | | | | | | |
| NET INCOME | |
| $69,625 |
| |
| $74,804 |
| |
| $57,881 |
| |
| $107,538 |
| |
| $69,625 |
| |
| $74,804 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
(Page left blank intentionally)
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $69,625 |
| |
| $74,804 |
| |
| $57,881 |
| |
| $107,538 |
| |
| $69,625 |
| |
| $74,804 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation and amortization | | 102,410 |
| | 99,609 |
| | 94,744 |
| | 107,026 |
| | 102,410 |
| | 99,609 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | (23,292 | ) | | 2,829 |
| | 86,152 |
| | 20,794 |
| | (23,292 | ) | | 2,829 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 21,443 |
| | 24,318 |
| | (49,252 | ) | | (9,300 | ) | | 21,443 |
| | 24,318 |
|
| Fuel inventory | | 2,960 |
| | 5,433 |
| | 53 |
| | 9,765 |
| | 2,960 |
| | 5,433 |
|
| Accounts payable | | (16,913 | ) | | (19,854 | ) | | 29,718 |
| | (22,462 | ) | | (16,913 | ) | | (19,854 | ) |
| Prepaid taxes and taxes accrued | | 3,484 |
| | 57,484 |
| | (1,967 | ) | | 10,018 |
| | 3,484 |
| | 57,484 |
|
| Interest accrued | | (551 | ) | | (1,489 | ) | | (920 | ) | | (3,229 | ) | | (551 | ) | | (1,489 | ) |
| Deferred fuel costs | | 36,985 |
| | (15,954 | ) | | (89,241 | ) | | 29,419 |
| | 36,985 |
| | (15,954 | ) |
| Other working capital accounts | | 2,468 |
| | 9,045 |
| | 6,918 |
| | (3,354 | ) | | 2,468 |
| | 9,045 |
|
| Provisions for estimated losses | | (2,899 | ) | | 3,139 |
| | 2,470 |
| | (1,735 | ) | | (2,899 | ) | | 3,139 |
|
| Other regulatory assets | | 125,133 |
| | 2,809 |
| | 197,520 |
| | 74,389 |
| | 125,133 |
| | 2,809 |
|
| Pension and other postretirement liabilities | | (33,474 | ) | | 59,725 |
| | (104,055 | ) | | (10,204 | ) | | (33,474 | ) | | 59,725 |
|
| Other assets and liabilities | | (3,111 | ) | | 13,266 |
| | 7,033 |
| | (2,064 | ) | | (3,111 | ) | | 13,266 |
|
| Net cash flow provided by operating activities | | 284,268 |
| | 315,164 |
| | 237,054 |
| | 306,601 |
| | 284,268 |
| | 315,164 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (320,408 | ) | | (195,794 | ) | | (181,546 | ) | | (337,963 | ) | | (320,408 | ) | | (195,794 | ) |
| Allowance for equity funds used during construction | | 5,751 |
| | 2,981 |
| | 4,647 |
| | 7,743 |
| | 5,751 |
| | 2,981 |
|
| Changes in money pool receivable - net | | 306 |
| | 5,981 |
| | 12,888 |
| | (681 | ) | | 306 |
| | 5,981 |
|
| Changes in securitization account | | (942 | ) | | 292 |
| | (256 | ) | | 710 |
| | (942 | ) | | 292 |
|
| Other | | — |
| | — |
| | (42 | ) | |
| Net cash flow used in investing activities | | (315,293 | ) | | (186,540 | ) | | (164,309 | ) | | (330,191 | ) | | (315,293 | ) | | (186,540 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | 246,607 |
| | 131,163 |
| | — |
| | 123,502 |
| | 246,607 |
| | 131,163 |
|
| Retirement of long-term debt | | (265,734 | ) | | (213,450 | ) | | (61,316 | ) | | (68,593 | ) | | (265,734 | ) | | (213,450 | ) |
| Change in money pool payable - net | | 22,068 |
| | — |
| | — |
| | (22,068 | ) | | 22,068 |
| | — |
|
| Dividends paid: | | |
| | |
| | |
| | |
| | |
| | |
|
| Common stock | | — |
| | (70,000 | ) | | (25,000 | ) | | — |
| | — |
| | (70,000 | ) |
| Other | | (175 | ) | | 7,616 |
| | (177 | ) | | (5,252 | ) | | (175 | ) | | 7,616 |
|
| Net cash flow provided by (used in) financing activities | | 2,766 |
| | (144,671 | ) | | (86,493 | ) | | 27,589 |
| | 2,766 |
| | (144,671 | ) |
| Net decrease in cash and cash equivalents | | (28,259 | ) | | (16,047 | ) | | (13,748 | ) | |
| Net increase (decrease) in cash and cash equivalents | | | 3,999 |
| | (28,259 | ) | | (16,047 | ) |
| Cash and cash equivalents at beginning of period | | 30,441 |
| | 46,488 |
| | 60,236 |
| | 2,182 |
| | 30,441 |
| | 46,488 |
|
| Cash and cash equivalents at end of period | |
| $2,182 |
| |
| $30,441 |
| |
| $46,488 |
| |
| $6,181 |
| |
| $2,182 |
| |
| $30,441 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $83,290 |
| |
| $85,695 |
| |
| $89,021 |
| |
| $88,489 |
| |
| $83,290 |
| |
| $85,695 |
|
| Income taxes | |
| $60,359 |
| |
| ($2,653 | ) | |
| ($57,473 | ) | |
| $28,523 |
| |
| $60,359 |
| |
| ($2,653 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $2,153 |
| |
| $1,733 |
| |
| $1,216 |
| |
| $2,153 |
|
| Temporary cash investments | | 29 |
| | 28,708 |
| | 4,965 |
| | 29 |
|
| Total cash and cash equivalents | | 2,182 |
| | 30,441 |
| | 6,181 |
| | 2,182 |
|
| Securitization recovery trust account | | 38,161 |
| | 37,219 |
| | 37,451 |
| | 38,161 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Customer | | 61,870 |
| | 70,993 |
| | 71,803 |
| | 61,870 |
|
| Allowance for doubtful accounts | | (474 | ) | | (672 | ) | | (828 | ) | | (474 | ) |
| Associated companies | | 42,279 |
| | 57,004 |
| | 39,447 |
| | 42,279 |
|
| Other | | 11,054 |
| | 10,985 |
| | 14,756 |
| | 11,054 |
|
| Accrued unbilled revenues | | 40,195 |
| | 38,363 |
| | 39,727 |
| | 40,195 |
|
| Total accounts receivable | | 154,924 |
| | 176,673 |
| | 164,905 |
| | 154,924 |
|
| Deferred fuel costs | | — |
| | 11,861 |
| |
| Accumulated deferred income taxes | | — |
| | 669 |
| |
| Fuel inventory - at average cost | | 46,942 |
| | 49,902 |
| | 37,177 |
| | 46,942 |
|
| Materials and supplies - at average cost | | 34,994 |
| | 33,892 |
| | 36,631 |
| | 34,994 |
|
| Prepayments and other | | 17,975 |
| | 29,211 |
| | 18,599 |
| | 17,975 |
|
| TOTAL | | 295,178 |
| | 369,868 |
| | 300,944 |
| | 295,178 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Investments in affiliates - at equity | | 620 |
| | 655 |
| | 600 |
| | 620 |
|
| Non-utility property - at cost (less accumulated depreciation) | | 376 |
| | 376 |
| | 376 |
| | 376 |
|
| Other | | 20,186 |
| | 19,085 |
| | 18,801 |
| | 20,186 |
|
| TOTAL | | 21,182 |
| | 20,116 |
| | 19,777 |
| | 21,182 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 3,923,100 |
| | 3,761,847 |
| | 4,274,069 |
| | 3,923,100 |
|
| Construction work in progress | | 210,964 |
| | 125,425 |
| | 111,227 |
| | 210,964 |
|
| TOTAL UTILITY PLANT | | 4,134,064 |
| | 3,887,272 |
| | 4,385,296 |
| | 4,134,064 |
|
| Less - accumulated depreciation and amortization | | 1,477,529 |
| | 1,454,701 |
| | 1,526,057 |
| | 1,477,529 |
|
| UTILITY PLANT - NET | | 2,656,535 |
| | 2,432,571 |
| | 2,859,239 |
| | 2,656,535 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 107,499 |
| | 123,407 |
| | 105,816 |
| | 107,499 |
|
Other regulatory assets (includes securitization property of $453,317 as of
December 31, 2015 and $521,424 as of December 31, 2014) | | 812,862 |
| | 922,087 |
| |
| Long-term receivables - associated companies | | 1,073 |
| | 26,156 |
| |
Other regulatory assets (includes securitization property of $384,609 as of
December 31, 2016 and $453,317 as of December 31, 2015) | | | 740,156 |
| | 812,862 |
|
| Other | | 4,253 |
| | 3,784 |
| | 7,149 |
| | 5,326 |
|
| TOTAL | | 925,687 |
| | 1,075,434 |
| | 853,121 |
| | 925,687 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $3,898,582 |
| |
| $3,897,989 |
| |
| $4,033,081 |
| |
| $3,898,582 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $— |
| |
| $200,000 |
| |
| Accounts payable: | | | | | | | | |
| Associated companies | | 106,065 |
| | 91,481 |
| |
| $47,867 |
| |
| $106,065 |
|
| Other | | 87,421 |
| | 87,910 |
| | 77,342 |
| | 87,421 |
|
| Customer deposits | | 44,537 |
| | 44,308 |
| | 44,419 |
| | 44,537 |
|
| Taxes accrued | | 5,333 |
| | 1,849 |
| | 15,351 |
| | 5,333 |
|
| Interest accrued | | 29,206 |
| | 29,757 |
| | 25,977 |
| | 29,206 |
|
| Deferred fuel costs | | 25,124 |
| | — |
| | 54,543 |
| | 25,124 |
|
| Other | | 10,363 |
| | 18,238 |
| | 9,388 |
| | 10,363 |
|
| TOTAL | | 308,049 |
| | 473,543 |
| | 274,887 |
| | 308,049 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,006,834 |
| | 1,046,618 |
| | 1,027,647 |
| | 1,006,834 |
|
| Accumulated deferred investment tax credits | | 13,835 |
| | 14,735 |
| | 12,934 |
| | 13,835 |
|
| Other regulatory liabilities | | 6,396 |
| | 5,125 |
| | 8,502 |
| | 6,396 |
|
| Asset retirement cost liabilities | | 6,124 |
| | 4,610 |
| | 6,470 |
| | 6,124 |
|
| Accumulated provisions | | 9,319 |
| | 12,218 |
| | 7,584 |
| | 9,319 |
|
| Pension and other postretirement liabilities | | 77,517 |
| | 111,011 |
| | 67,313 |
| | 77,517 |
|
| Long-term debt (includes securitization bonds of $497,030 as of December 31, 2015 and $561,874 as of December 31, 2014) | | 1,451,967 |
| | 1,268,835 |
| |
| Long-term debt (includes securitization bonds of $429,043 as of December 31, 2016 and $497,030 as of December 31, 2015) | | | 1,508,407 |
| | 1,451,967 |
|
| Other | | 57,085 |
| | 69,463 |
| | 50,343 |
| | 57,085 |
|
| TOTAL | | 2,629,077 |
| | 2,532,615 |
| | 2,689,200 |
| | 2,629,077 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2015 and 2014 | | 49,452 |
| | 49,452 |
| |
| Common stock, no par value, authorized 200,000,000 shares; issued and outstanding 46,525,000 shares in 2016 and 2015 | | | 49,452 |
| | 49,452 |
|
| Paid-in capital | | 481,994 |
| | 481,994 |
| | 481,994 |
| �� | 481,994 |
|
| Retained earnings | | 430,010 |
| | 360,385 |
| | 537,548 |
| | 430,010 |
|
| TOTAL | | 961,456 |
| | 891,831 |
| | 1,068,994 |
| | 961,456 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,898,582 |
| |
| $3,897,989 |
| |
| $4,033,081 |
| |
| $3,898,582 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | CONSOLIDATED STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | | | | |
| | Common Equity | | | Common Equity | | |
| | Common Stock | | Paid-in Capital | | Retained Earnings | | Total | Common Stock | | Paid-in Capital | | Retained Earnings | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | |
| Balance at December 31, 2012 |
| $49,452 |
| |
| $481,994 |
| |
| $322,700 |
| |
| $854,146 |
| |
| Net income | — |
| | — |
| | 57,881 |
| | 57,881 |
| |
| Common stock dividends | — |
| | — |
| | (25,000 | ) | | (25,000 | ) | |
| Balance at December 31, 2013 |
| $49,452 |
| |
| $481,994 |
| |
| $355,581 |
| |
| $887,027 |
|
| $49,452 |
| |
| $481,994 |
| |
| $355,581 |
| |
| $887,027 |
|
| Net income | — |
| | — |
| | 74,804 |
| | 74,804 |
| — |
| | — |
| | 74,804 |
| | 74,804 |
|
| Common stock dividends | — |
| | — |
| | (70,000 | ) | | (70,000 | ) | — |
| | — |
| | (70,000 | ) | | (70,000 | ) |
| Balance at December 31, 2014 |
| $49,452 |
| |
| $481,994 |
| |
| $360,385 |
| |
| $891,831 |
|
| $49,452 |
| |
| $481,994 |
| |
| $360,385 |
| |
| $891,831 |
|
| Net income | — |
| | — |
| | 69,625 |
| | 69,625 |
| — |
| | — |
| | 69,625 |
| | 69,625 |
|
| Balance at December 31, 2015 |
| $49,452 |
| |
| $481,994 |
| |
| $430,010 |
| |
| $961,456 |
|
| $49,452 |
| |
| $481,994 |
| |
| $430,010 |
| |
| $961,456 |
|
| Net income | | — |
| | — |
| | 107,538 |
| | 107,538 |
|
| Balance at December 31, 2016 | |
| $49,452 |
| |
| $481,994 |
| |
| $537,548 |
| |
| $1,068,994 |
|
| | | | | | | | | | | | | | | |
| See Notes to Financial Statements. | See Notes to Financial Statements. | | |
| | |
| | |
| See Notes to Financial Statements. | | |
| | |
| | |
|
| | ENTERGY TEXAS, INC. AND SUBSIDIARIES | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $1,707,203 |
| |
| $1,851,982 |
| |
| $1,728,799 |
| |
| $1,581,496 |
| |
| $1,757,199 |
|
| $1,615,619 |
| |
| $1,707,203 |
| |
| $1,851,982 |
| |
| $1,728,799 |
| |
| $1,581,496 |
|
| Net Income |
| $69,625 |
| |
| $74,804 |
| |
| $57,881 |
| |
| $41,971 |
| |
| $80,845 |
| |
| Net income | |
| $107,538 |
| |
| $69,625 |
| |
| $74,804 |
| |
| $57,881 |
| |
| $41,971 |
|
| Total assets |
| $3,898,582 |
| |
| $3,897,989 |
| |
| $3,909,470 |
| |
| $4,011,618 |
| |
| $4,042,624 |
|
| $4,033,081 |
| |
| $3,898,582 |
| |
| $3,897,989 |
| |
| $3,909,470 |
| |
| $4,011,618 |
|
| Long-term obligations (a) |
| $1,451,967 |
| |
| $1,268,835 |
| |
| $1,544,549 |
| |
| $1,603,650 |
| |
| $1,660,745 |
|
| $1,508,407 |
| |
| $1,451,967 |
| |
| $1,268,835 |
| |
| $1,544,549 |
| |
| $1,603,650 |
|
| | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt). | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (Dollars In Millions) | (Dollars In Millions) |
| | | | | | | | | | | | | | | | | | | |
| Electric Operating Revenues: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Residential |
| $633 |
| |
| $654 |
| |
| $596 |
| |
| $553 |
| |
| $638 |
|
| $613 |
| |
| $633 |
| |
| $654 |
| |
| $596 |
| |
| $553 |
|
| Commercial | 369 |
| | 384 |
| | 327 |
| | 325 |
| | 369 |
| 356 |
| | 369 |
| | 384 |
| | 327 |
| | 325 |
|
| Industrial | 372 |
| | 422 |
| | 325 |
| | 299 |
| | 352 |
| 365 |
| | 372 |
| | 422 |
| | 325 |
| | 299 |
|
| Governmental | 25 |
| | 26 |
| | 24 |
| | 24 |
| | 26 |
| 24 |
| | 25 |
| | 26 |
| | 24 |
| | 24 |
|
| Total retail | 1,399 |
| | 1,486 |
| | 1,272 |
| | 1,201 |
| | 1,385 |
| 1,358 |
| | 1,399 |
| | 1,486 |
| | 1,272 |
| | 1,201 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 259 |
| | 316 |
| | 369 |
| | 313 |
| | 262 |
| 178 |
| | 259 |
| | 316 |
| | 369 |
| | 313 |
|
| Non-associated companies | 14 |
| | 23 |
| | 47 |
| | 36 |
| | 74 |
| 40 |
| | 14 |
| | 23 |
| | 47 |
| | 36 |
|
| Other | 35 |
| | 27 |
| | 41 |
| | 31 |
| | 36 |
| 40 |
| | 35 |
| | 27 |
| | 41 |
| | 31 |
|
| Total |
| $1,707 |
| |
| $1,852 |
| |
| $1,729 |
| |
| $1,581 |
| |
| $1,757 |
|
| $1,616 |
| |
| $1,707 |
| |
| $1,852 |
| |
| $1,729 |
| |
| $1,581 |
|
| | | | | | | | | | | | | | | | | | | |
| Billed Electric Energy Sales (GWh): | | | |
| | |
| | |
| | |
| | | |
| | |
| | |
| | |
|
| Residential | 5,889 |
| | 5,810 |
| | 5,726 |
| | 5,604 |
| | 6,034 |
| 5,836 |
| | 5,889 |
| | 5,810 |
| | 5,726 |
| | 5,604 |
|
| Commercial | 4,548 |
| | 4,471 |
| | 4,402 |
| | 4,396 |
| | 4,433 |
| 4,570 |
| | 4,548 |
| | 4,471 |
| | 4,402 |
| | 4,396 |
|
| Industrial | 7,036 |
| | 7,140 |
| | 6,404 |
| | 6,066 |
| | 6,102 |
| 7,493 |
| | 7,036 |
| | 7,140 |
| | 6,404 |
| | 6,066 |
|
| Governmental | 276 |
| | 277 |
| | 282 |
| | 278 |
| | 294 |
| 283 |
| | 276 |
| | 277 |
| | 282 |
| | 278 |
|
| Total retail | 17,749 |
| | 17,698 |
| | 16,814 |
| | 16,344 |
| | 16,863 |
| 18,182 |
| | 17,749 |
| | 17,698 |
| | 16,814 |
| | 16,344 |
|
| Sales for resale: | |
| | |
| | |
| | |
| | |
| |
| | |
| | |
| | |
| | |
|
| Associated companies | 5,853 |
| | 4,763 |
| | 6,287 |
| | 5,702 |
| | 4,158 |
| 4,625 |
| | 5,853 |
| | 4,763 |
| | 6,287 |
| | 5,702 |
|
| Non-associated companies | 254 |
| | 200 |
| | 712 |
| | 827 |
| | 1,258 |
| 1,086 |
| | 254 |
| | 200 |
| | 712 |
| | 827 |
|
| Total | 23,856 |
| | 22,661 |
| | 23,813 |
| | 22,873 |
| | 22,279 |
| 23,893 |
| | 23,856 |
| | 22,661 |
| | 23,813 |
| | 22,873 |
|
SYSTEM ENERGY RESOURCES, INC.
MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS
System Energy’s principal asset currently consists of 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’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’s only source of operating revenues.
Results of Operations
Net Income
2016 Compared to 2015
Net income decreased $14.6 million primarily due to a higher effective income tax rate in 2016.
2015 Compared to 2014
Net income increased $15 million primarily due to a higher effective income tax rate in 2014, partially offset by lower operating revenue resulting from lower rate base as compared to the prior year.
2014 Compared to 2013
Net income decreased $17.3 million primarily due to a higher effective income tax rate and lower operating revenues resulting from lower rate base as compared with the same period in the prior year, partially offset by higher other regulatory credits. System Energy records a regulatory debit or credit for the difference between asset retirement obligation-related expenses and trust earnings plus asset retirement obligation-related costs collected in revenue. The increase in regulatory credits for 2014 compared to 2013 is primarily caused by increases in depreciation and accretion expenses and regulatory credits recorded in 2014 to realign the asset retirement obligation regulatory asset with regulatory treatment.
Income Taxes
The effective income tax rates for 2016, 2015, and 2014 and 2013 were 42.3%, 32.3%, 46.4%, and 37.7%46.4%, respectively. See Note 3 to the financial statements for a reconciliation of the federal statutory rate of 35% to the effective income tax rates.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Liquidity and Capital Resources
Cash Flow
Cash flows for the years ended December 31, 2016, 2015, 2014, and 20132014 were as follows:
| | | | 2015 | | 2014 | | 2013 | 2016 | | 2015 | | 2014 |
| | (In Thousands) | (In Thousands) |
| Cash and cash equivalents at beginning of period |
| $223,179 |
| |
| $127,142 |
| |
| $83,622 |
|
| $230,661 |
| |
| $223,179 |
| |
| $127,142 |
|
| | | | | | | | | | | |
| Net cash provided by (used in): | | | |
| | |
| | | |
| | |
|
| Operating activities | 502,536 |
| | 428,265 |
| | 279,638 |
| 341,939 |
| | 502,536 |
| | 428,265 |
|
| Investing activities | (137,562 | ) | | (203,930 | ) | | (96,852 | ) | (232,602 | ) | | (137,562 | ) | | (203,930 | ) |
| Financing activities | (357,492 | ) | | (128,298 | ) | | (139,266 | ) | (94,135 | ) | | (357,492 | ) | | (128,298 | ) |
| Net increase in cash and cash equivalents | 7,482 |
| | 96,037 |
| | 43,520 |
| 15,202 |
| | 7,482 |
| | 96,037 |
|
| | | | | | | | | | | |
| Cash and cash equivalents at end of period |
| $230,661 |
| |
| $223,179 |
| |
| $127,142 |
|
| $245,863 |
| |
| $230,661 |
| |
| $223,179 |
|
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Operating Activities
Net cash flow provided by operating activities decreased $160.6 million in 2016 primarily due to:
a decrease of $90.5 million in income tax refunds in 2016. System Energy received income tax refunds in 2016 and 2015 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2016 and 2015 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method; and
an increase in spending of $35.1 million on nuclear refueling outages in 2016 as compared to 2015.
The decrease was partially offset by proceeds of $28.4 million received in August 2016 from the DOE resulting from litigation regarding spent nuclear fuel storage costs that were previously expensed. See Note 8 to the financial statements for a discussion of the spent nuclear fuel litigation.
Net cash flow provided by operating activities increased $74.3 million in 2015 primarily due to an increase in income tax refunds of $104 million in 2015 and a decrease of $40.2 million in spending on nuclear refueling outages in 2015. The increase was partially offset by an increase in interest paid on the Grand Gulf sale-leaseback obligation as a result of the renewal in December 2013. System Energy received income tax refunds in 2015 and 2014 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax refunds in 2015 resulted primarily from the adoption of a new accounting method for income tax purposes in which System Energy will treat its nuclear decommissioning costs as production costs of electricity includable in cost of goods sold. See Note 3 to the financial statements for further discussion of the adoption of the new accounting method. See Note 10 to the financial statements for details on the Grand Gulf sale-leaseback obligation.
Investing Activities
Net cash flow provided by operatingused in investing activities increased $148.6$95 million in 20142016 primarily due to:
fluctuations in nuclear fuel activity because of variations from year to income tax refundsyear in the timing and pricing of $10.1 millionfuel reload requirements in 2014 compared to income taxthe Utility business, material and services deliveries, and the timing of cash payments during the nuclear fuel cycle; and
an increase in nuclear construction expenditures primarily as a result of $211.2 milliona higher scope of work performed in 2013. 2016 on Grand Gulf outage projects, partially offset by decreased spending in 2016 on compliance with NRC post-Fukushima requirements.
The increase was partially offset by spending on the Grand Gulf refueling outagemoney pool activity and proceeds of $15.8 million received in 2014 and an increase of $12.9 million in pension contributions in 2014. System Energy made income tax payments in 2013 in accordance with the Entergy Corporation and Subsidiary Companies Intercompany Income Tax Allocation Agreement. The income tax payments in 2013 resulted primarilyAugust 2016 from the reversal of temporary differences for which System Energy hadDOE resulting from litigation regarding spent nuclear fuel storage costs that were previously claimed a tax deduction.capitalized. See “Critical Accounting Estimates”below and Note 118 to the financial statements for a discussion of qualified pension and other postretirement benefits funding.the spent nuclear fuel litigation.
Investing ActivitiesDecreases 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 by $6.1 million in 2016 compared to increasing by $37.6 million in 2015. 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 decreased $66.4 million in 2015 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. The decrease was partially offset by money pool activity and an increase in nuclear expenditures primarily due to compliance with NRC post-Fukushima requirements.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Increases in System Energy’s receivable from the money pool are a use of cash flow and System Energy’s receivable from the money pool increased by $37.6 million in 2015 compared to decreasing by $6.9 million in 2014. The money pool is an inter-company borrowing arrangement designed to reduce the Utility subsidiaries’ need for external short-term borrowings.
System Energy Resources, Inc.
Management’s Financial Discussion and AnalysisFinancing Activities
Net cash flow used in investingfinancing activities increased $107.1decreased $263.4 million in 20142016 primarily due to:
fluctuations in nuclear fuel activity becausenet borrowings 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$66.9 million on the nuclear fuel cycle;company variable interest entity’s credit facility in 2016 compared to net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015;
an increasea decrease of $61.8 million in nuclear construction expenditures primarilycommon stock dividends and distributions as a result of spending onlower operating cash flows and higher nuclear projects duringfuel purchases in 2016 as compared to the Grand Gulf refueling outageprior year;
the redemption in 2014;April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes; and
money pool activity.redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022.
DecreasesThe decrease was partially offset by the partial repayment caused by System Energy in May 2016 of $22 million of 5.875% pollution control revenue bonds due 2022 issued on behalf of System Energy’s receivable from the money pool are a source of cash flow and System Energy’s
receivable from the money pool decreased by $6.9 million in 2014 compared to decreasing by $17.7 million in 2013.
Financing ActivitiesEnergy.
Net cash flow used by financing activities increased $229.2 million in 2015 primarily due to:
an increase of $98.8 million in common stock dividends and distributions;distributions primarily due to higher operating cash flows and lower nuclear fuel purchases in 2015 as compared to the prior year;
redemption in April 2015, at maturity, of $60 million of System Energy nuclear fuel company variable interest entity’s 5.33% Series G notes;
redemption in May 2015 of $35 million and in November 2015 of $25 million of System Energy’s 5.875% Series governmental bonds due 2022; and
net repayments of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2015 compared to net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014.
The increase was partially offset by a decrease of $30.4 million in principal payments on the Grand Gulf sale-leaseback obligation in 2015 as compared to 2014. See Note 10 to the financial statements for details on the Grand Gulf sale-leaseback obligation.
Net cash used in financing activities decreased $11 million in 2014 primarily due to:
the redemption of $70 million of 6.29% Series F notes by the nuclear fuel company variable interest entity in September 2013; and
net borrowings of $20.4 million on the nuclear fuel company variable interest entity’s credit facility in 2014 compared to net repayments of $40 million on the nuclear fuel company variable interest entity’s credit facility in 2013.
The decrease was partially offset by the issuance of $85 million of 3.78% Series I notes by the nuclear fuel company variable interest entity in October 2013 and an increase of $31.6 million in common stock dividends paid in 2014.
See Note 5 to the financial statements for details of long-term debt.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Capital Structure
System Energy’s capitalization is balanced between equity and debt, as shown in the following table. The decreaseincrease in the debt to capital ratio for System Energy as of December 31, 2015 is primarily due to net borrowings of $66.9 million on the redemptions of long-term debt, as discussed above.System Energy nuclear fuel company variable interest entity’s credit facility and common stock dividends and distributions in 2016.
| | | | December 31,
2015 | | December 31,
2014 | December 31,
2016 | | December 31,
2015 |
| Debt to capital | 42.3 | % | | 45.7 | % | 45.5 | % | | 42.3 | % |
| Effect of subtracting cash | (11.8 | %) | | (8.8 | %) | (12.0 | %) | | (11.8 | %) |
| Net debt to net capital | 30.5 | % | | 36.9 | % | 33.5 | % | | 30.5 | % |
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Net debt consists of debt less cash and cash equivalents. Debt consists of short-term borrowings and long-term debt, including the currently maturing portion. Capital consists of debt and common equity. Net capital consists of capital less cash and cash equivalents. System Energy uses the debt to capital ratio in analyzing its financial condition and believes it provides useful information to its investors and creditors in evaluating System Energy’s financial condition. 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’s financial condition because net debt indicates System Energy’s outstanding debt position that could not be readily satisfied by cash and cash equivalents on hand.
System Energy seeks to optimize its capital structure in accordance with its regulatory requirements and to control its cost of capital while also maintaining equity capitalization at a level consistent with investment-grade debt ratings. To the extent that operating cash flows are in excess of planned investments, cash may be used to reduce outstanding debt or may be paid as a dividend, or both, in appropriate amounts to maintain the targeted capital structure. To the extent that operating cash flows are insufficient to support planned investments, System Energy may issue incremental debt or reduce dividends, or both, to maintain its targeted capital structure.
Uses of Capital
System Energy requires capital resources for:
construction and other capital investments;
debt maturities or retirements;
working capital purposes, including the financing of fuel costs; and
dividend, distribution, and interest payments.
Following are the amounts of System Energy’s planned construction and other capital investments.
| | | | 2016 | | 2017 | | 2018 | 2017 | | 2018 | | 2019 |
| | (In Millions) | (In Millions) |
| Planned construction and capital investment: | | | | | | | | | | |
| Generation |
| $90 |
| |
| $50 |
| |
| $65 |
|
| $90 |
| |
| $165 |
| |
| $165 |
|
| Other | 5 |
| | 10 |
| | 15 |
| 10 |
| | 10 |
| | 10 |
|
| Total |
| $95 |
| |
| $60 |
| |
| $80 |
|
| $100 |
| |
| $175 |
| |
| $175 |
|
Following are the amounts of System Energy’s existing debt and lease obligations (includes estimated interest payments) and other purchase obligations.
| | | | 2016 | | 2017-2018 | | 2019-2020 | | After 2020 | | Total | 2017 | | 2018-2019 | | 2020-2021 | | After 2021 | | Total |
| | (In Millions) | (In Millions) |
| Long-term debt (a) |
| $42 |
| |
| $214 |
| |
| $73 |
| |
| $716 |
| |
| $1,045 |
|
| $89 |
| |
| $158 |
| |
| $71 |
| |
| $656 |
| |
| $974 |
|
| Purchase obligations (b) |
| $38 |
| |
| $38 |
| |
| $34 |
| |
| $36 |
| |
| $146 |
|
| $13 |
| |
| $37 |
| |
| $33 |
| |
| $33 |
| |
| $116 |
|
| |
| (a) | Includes estimated interest payments. Long-term debt is discussed in Note 5 to the financial statements. |
| |
| (b) | 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. |
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In addition to the contractual obligations given above, System Energy expects to contribute approximately $20.2$18.1 million to its qualified pension plans and approximately $20$690 thousand to other postretirement health care and life insurance plans in 2016,2017, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017. See “Critical Accounting Estimates – Qualified Pension and Other Postretirement Benefits” below for a discussion of qualified pension and other postretirement benefits funding.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Also in addition to the contractual obligations, System Energy has $344.7$382.3 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.
In addition to routine spending to maintain operations, the planned capital investment estimate includes specific investments and initiatives such as NRC post-Fukushima requirementsthe nuclear fleet operational excellence initiative, as discussed below in “Nuclear Matters,” and plant improvements.
As a wholly-owned subsidiary, System Energy dividends its earnings to Entergy Corporation at a percentage determined monthly. Currently, all of System Energy’s retained earnings are available for distribution.
Sources of Capital
System Energy’s sources to meet its capital requirements include:
internally generated funds;
cash on hand;
debt issuances; and
bank financing under new or existing facilities.
System Energy may refinance, redeem, or otherwise 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’s receivables from the money pool were as follows as of December 31 for each of the following years.
|
| | | | | | |
| 2015 | | 2014 | | 2013 | | 2012 |
| (In Thousands) |
| $39,926 | | $2,373 | | $9,223 | | $26,915 |
|
| | | | | | |
| 2016 | | 2015 | | 2014 | | 2013 |
| (In Thousands) |
| $33,809 | | $39,926 | | $2,373 | | $9,223 |
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 $125$120 million scheduled to expire in June 2016.May 2019. As of December 31, 2015, there were no2016, $66.9 million in letters of credit were outstanding onunder the credit facility to support a like amount of commercial paper issued by the System Energy nuclear fuel company variable interest entity credit facility.entity. See Note 4 to the financial statements for additional discussion of the variable interest entity credit facilities.facility.
System Energy obtained authorizations from the FERC through October 2017 for the following:
short-term borrowings not to exceed an aggregate amount of $200 million at any time outstanding;
long-term borrowings and security issuances; and
long-term borrowings by its nuclear fuel company variable interest entity.
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
See Note 4 to the financial statements for further discussion of System Energy’s short-term borrowing limits.
System Energy nuclear fuel company variable interest entity redeemed, at maturity, its $60 millionResources, Inc.
Management’s Financial Discussion and Analysis
Federal Regulation
See the “Rate, Cost-recovery, and Other Regulation– Federal Regulation” section of 5.33% Series G Notes.Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis and Note 2 to the financial statements for a discussion of federal regulation.
Complaint Against System Energy
In May 2015,January 2017 the APSC and MPSC filed a complaint with the FERC against System Energy. The complaint seeks a reduction in the return on equity component of the Unit Power Sales Agreement pursuant to which System Energy redeemed $35 millionsells its Grand Gulf capacity and energy to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans. Entergy Arkansas also sells some of its $216 millionGrand Gulf capacity and energy to Entergy Louisiana, Entergy Mississippi, and Entergy New Orleans under separate agreements. The current return on equity under the Unit Power Sales Agreement is 10.94%. The complaint alleges that the return on equity is unjust and unreasonable because current capital market and other considerations indicate that it is excessive. The complaint requests the FERC to institute proceedings to investigate the return on equity and establish a lower return on equity, and also requests that the FERC establish January 23, 2017 as a refund effective date. The complaint includes return on equity analysis that purports to establish that the range of 5.875% Series governmental bonds due 2022. In November 2015,reasonable return on equity for System Energy redeemed $25 millionis between 8.37% and 8.67%. System Energy answered the complaint in February 2017 and disputes a return on equity of its $216 million of 5.875% Series governmental bonds due 2022.8.37% to 8.67% is just and reasonable. Action by the FERC is pending.
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 withDecember 2016, the NRC for angranted the extension of Grand Gulf’s operating license to 2044, which application is pending.2044.
In June 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 that2016, Entergy conducted 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 requirementscomprehensive evaluation of the National Environmental Policy Act (NEPA) whenEntergy nuclear fleet and determined that it considered environmental effectsis necessary to increase investments in reaching these conclusions.its nuclear plants to position the fleet to meet its operational goals. These investments will result in increased operating and capital costs associated with operating Entergy’s nuclear plants going forward. The Waste Confidence Decision has been relied upon by NRC license renewal applicants to address somepreliminary estimates of the issues thatincrease to planned capital costs for 2017 through 2019 identified through and associated with this initiative are estimated to be $265 million for System Energy. The current estimates of the NEPA requires the NRCcapital costs identified through this initiative are included in System Energy’s capital investment plan preliminary estimate for 2017 through 2019 given in “Liquidity and Capital Resources - Uses of Capital” above. The increase to address before it issuesplanned other operation and maintenance expenses identified through and associated with this initiative is preliminarily estimated to be approximately $35 million in 2017 for System Energy, with a renewed license. Certain nuclear opponents filed requests with the NRC asking itsimilar level of expenses expected to address the issues raised by the court’s decision in the license renewal proceedings for a number of nuclear plants including Grand Gulf. In August 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 movegoing forward. In September 2014 the NRC published a new final Waste Confidence rule, named Continued Storage of Spent Nuclear Fuel, that for licensing purposes adopts non-site specific findings concerning the environmental impacts of the continued storage of spentaddition, nuclear fuel at reactor sites - for 60 years, 100 years and indefinitely - after the reactor’s licensed period of operations. The NRC also issued an order lifting its suspension of licensing proceedings after the final rule’s effective date in October 2014. After the final rule became effective, New York, Connecticut, and Vermont filed a challengerefueling outage expenses are expected to the rule in the U.S. Court of Appeals. The final rule remains in effect while that challenge is pending unless the court orders otherwise.increase going forward.
The nuclear industry continues to address susceptibility to stress corrosion cracking of certain materials within the reactor coolant system.plant systems. The issue is applicable at all nuclear units to Grand Gulfvarying degrees and is managed in accordance with industry standard practices and guidelines that include in-service examinations, replacements, and mitigation strategies. Developments in the industry or identification of issues at the nuclear units could require unanticipated remediation efforts that cannot be quantified in advance.
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 in March 2012. The three
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
Grand Gulf Outage and NRC review
orders require U.S. nuclear operatorsGrand Gulf began a maintenance outage on September 8, 2016 to undertakereplace a residual heat removal pump. Although the pump had been replaced, on September 27, 2016 management decided to keep the plant modificationsin an outage for additional training and perform additional analyses that will, among other things, resultsteps to support management’s operational goals. Grand Gulf returned to service on January 31, 2017.
Based on the plant’s recent performance indicators, in increased operating and capital costs associated with operating nuclear plants. The NRC, with input from the industry, is continuing to determine the specific actions required by the orders. System Energy’s estimated capital expenditures forNovember 2016 through 2018 for complying with the NRC orders are includedplaced Grand Gulf in the planned construction“regulatory response column,” or Column 2, of its Reactor Oversight Process Action Matrix. Additionally, in October 2016 the NRC commenced a special inspection to investigate the circumstances surrounding the unplanned unavailability of an alternate heat removal system during the September 2016 replacement of the heat removal pump and other capital investments estimates given in “Liquidityto evaluate the licensee’s actions to address the causes of the event. Depending upon the findings of the NRC and Capital Resources - Usesthe plant’s performance indicators, there is risk that the NRC could move Grand Gulf into the “degraded cornerstone column,” or Column 3, of Capital” above.the NRC’s Reactor Oversight Action Matrix.
Environmental Risks
System Energy’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.
Critical Accounting Estimates
The preparation of System Energy’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’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.
In the fourth quarter 2015, 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 $2.5 million reduction in its decommissioning cost liability, along with a corresponding reduction in the related asset retirement cost asset that will be depreciated over the remaining life of the unit.
InUtility Regulatory Accounting
See “Utility Regulatory Accounting” in the fourth quarter 2014, “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for discussion of accounting for the effects of rate regulation.
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 $99.9 million increase in its decommissioning liability, along with a corresponding increaseResources, Inc.
Management’s Financial Discussion and Analysis
Taxation and Uncertain Tax Positions
See “Taxation and Uncertain Tax Positions” in the related asset retirement cost asset that will be depreciated over the remaining life“Critical Accounting Estimates” section of the unit.Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for further discussion.
Qualified Pension and Other Postretirement Benefits
System Energy’s qualified pension and other postretirement reported costs, 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 “Qualified Pension and Other Postretirement Benefits” in 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.
System Energy Resources, 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 2015 Qualified Pension Cost | | Impact on 2015 Projected Qualified Benefit Obligation | | Change in Assumption | | Impact on 2017 Qualified Pension Cost | | Impact on 2016 Projected Qualified Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $1,162 | | $10,512 | | (0.25%) | | $884 | |
| $11,222 |
|
| Rate of return on plan assets | | (0.25%) | | $125 | | $— | | (0.25%) | | $620 | | $- |
|
| Rate of increase in compensation | | 0.25% | | $411 | | $1,623 | | 0.25% | | $327 | |
| $1,772 |
|
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 2015 Postretirement Benefit Cost | | Impact on 2015 Accumulated Postretirement Benefit Obligation | | Change in Assumption | | Impact on 2017 Postretirement Benefit Cost | | Impact on 2016 Accumulated Postretirement Benefit Obligation |
| | | | | Increase/(Decrease) | | | | | | Increase/(Decrease) | | |
| Discount rate | | (0.25%) | | $170 | | $1,963 | | (0.25%) | | $173 | | $2,082 |
| Health care cost trend | | 0.25% | | $289 | | $1,772 | | 0.25% | | $277 | | $1,841 |
Each fluctuation above assumes that the other components of the calculation are held constant.
Costs and Funding
Total qualified pension cost for System Energy in 20152016 was $16.6$10.8 million. System Energy anticipates 20162017 qualified pension cost to be $10.8$11.7 million. In 2016, System refined its approach to estimating the service cost and interest cost components of qualified pension costs, which had the effect of lowering qualified pension costs by $2.8 million. System Energy contributed $20.8$20.5 million to its pension plans in 20152016 and estimates 2016-20182017 pension contributions will approximate $51.5$18.1 million, including $20.2 million in 2016, although the 20162017 required pension contributions will be known with more certainty when the January 1, 20162017 valuations are completed, which is expected by April 1, 2016.2017.
Total postretirement health care and life insurance benefit costsincome for System Energy in 2015 were $4812016 was $224 thousand. System Energy expects 20162017 postretirement health care and life insurance benefit incomecost to approximate $224 $692
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
thousand. In 2016, System Energy refined its approach to estimating the service cost and interest cost components of other postretirement costs, which had the effect of lowering qualified other postretirement costs by $555 thousand. System Energy contributed $260$330 thousand to its other postretirement plans in 20152016 and expects 2016-20182017 contributions to approximate $60 thousand, including $20 thousand in 2016.$690 thousand.
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 2014 actuarial study reviewed plan experience from 2010 through 2013. As a result of the 2014 actuarial study and the issuance of new mortality tables in October 2014 by the Society of Actuaries, changes were made to reflect modified demographic pattern expectations as well as longer life expectancies. These changes are reflected in the December 31, 2014 financial disclosures. Adoption of the new mortality assumptions for 2015 resulted in an increase at December 31, 2014 of $17.7 million in the qualified pension benefit obligation and $3.1 million in the accumulated postretirement obligation. The new mortality assumptions increased anticipated 2015 qualified pension cost by approximately $2.7 million and other postretirement cost by approximately $0.4 million. Pension funding guidelines, as established by
System Energy Resources, Inc.
Management’s Financial Discussion and Analysis
In 2016, the Employee Retirement Income Security Act of 1974, as amended andmortality projection scale was updated to MP-2016, with no change in the Internal Revenue Code of 1986, as amended, are not expected to incorporate the October 2014 Society of Actuaries newbase mortality assumptions until after 2015, possibly 2016.table assumption.
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.
Other Contingencies
See “Other Contingencies” in the “Critical Accounting Estimates” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis for a discussion of the estimates associated with environmental, litigation, and other risks.
New Accounting Pronouncements
See “New Accounting Pronouncements” section of Entergy Corporation and Subsidiaries Management’s Financial Discussion and Analysis.
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 accompanying balance sheets of System Energy Resources, Inc. (the “Company”) as of December 31, 20152016 and 2014,2015, and the related income statements, statements of cash flows, and statements of changes in common equity (pages 436 through 440 and applicable items in pages 6159 through 236)232) for each of the three years in the period ended December 31, 2015.2016. 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. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, 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, 20152016 and 2014,2015, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2015,2016, in conformity with accounting principles generally accepted in the United States of America.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
| | SYSTEM ENERGY RESOURCES, INC. | INCOME STATEMENTS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | | | | | |
| OPERATING REVENUES | | | | | | | | | | | | |
| Electric | |
| $632,405 |
| |
| $664,364 |
| |
| $735,089 |
| |
| $548,291 |
| |
| $632,405 |
| |
| $664,364 |
|
| | | | | | | | | | | | | |
| OPERATING EXPENSES | | |
| | |
| | |
| | |
| | |
| | |
|
| Operation and Maintenance: | | |
| | |
| | |
| | |
| | |
| | |
|
| Fuel, fuel-related expenses, and gas purchased for resale | | 89,598 |
| | 84,658 |
| | 103,358 |
| | 27,416 |
| | 89,598 |
| | 84,658 |
|
| Nuclear refueling outage expenses | | 21,654 |
| | 23,309 |
| | 29,551 |
| | 19,512 |
| | 21,654 |
| | 23,309 |
|
| Other operation and maintenance | | 156,552 |
| | 156,502 |
| | 174,772 |
| | 153,064 |
| | 156,552 |
| | 156,502 |
|
| Decommissioning | | 47,993 |
| | 41,835 |
| | 35,472 |
| | 50,797 |
| | 47,993 |
| | 41,835 |
|
| Taxes other than income taxes | | 27,281 |
| | 25,160 |
| | 25,537 |
| | 25,195 |
| | 27,281 |
| | 25,160 |
|
| Depreciation and amortization | | 143,133 |
| | 142,583 |
| | 176,387 |
| | 136,195 |
| | 143,133 |
| | 142,583 |
|
| Other regulatory credits - net | | (39,434 | ) | | (30,799 | ) | | (13,068 | ) | | (45,041 | ) | | (39,434 | ) | | (30,799 | ) |
| TOTAL | | 446,777 |
| | 443,248 |
| | 532,009 |
| | 367,138 |
| | 446,777 |
| | 443,248 |
|
| | | | | | | | | | | | | |
| OPERATING INCOME | | 185,628 |
| | 221,116 |
| | 203,080 |
| | 181,153 |
| | 185,628 |
| | 221,116 |
|
| | | | | | | | | | | | | |
| OTHER INCOME | | |
| | |
| | |
| | |
| | |
| | |
|
| Allowance for equity funds used during construction | | 8,494 |
| | 5,069 |
| | 7,784 |
| | 7,944 |
| | 8,494 |
| | 5,069 |
|
| Interest and investment income | | 14,437 |
| | 11,037 |
| | 9,844 |
| | 14,793 |
| | 14,437 |
| | 11,037 |
|
| Miscellaneous - net | | (876 | ) | | (529 | ) | | (804 | ) | | (556 | ) | | (876 | ) | | (529 | ) |
| TOTAL | | 22,055 |
| | 15,577 |
| | 16,824 |
| | 22,181 |
| | 22,055 |
| | 15,577 |
|
| | | | | | | | | | | | | |
| INTEREST EXPENSE | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest expense | | 45,532 |
| | 58,384 |
| | 38,173 |
| | 37,529 |
| | 45,532 |
| | 58,384 |
|
| Allowance for borrowed funds used during construction | | (2,244 | ) | | (1,335 | ) | | (786 | ) | | (2,000 | ) | | (2,244 | ) | | (1,335 | ) |
| TOTAL | | 43,288 |
| | 57,049 |
| | 37,387 |
| | 35,529 |
| | 43,288 |
| | 57,049 |
|
| | | | | | | | | | | | | |
| INCOME BEFORE INCOME TAXES | | 164,395 |
| | 179,644 |
| | 182,517 |
| | 167,805 |
| | 164,395 |
| | 179,644 |
|
| | | | | | | | | | | | | |
| Income taxes | | 53,077 |
| | 83,310 |
| | 68,853 |
| | 71,061 |
| | 53,077 |
| | 83,310 |
|
| | | | | | | | | | | | | |
| NET INCOME | |
| $111,318 |
| |
| $96,334 |
| |
| $113,664 |
| |
| $96,744 |
| |
| $111,318 |
| |
| $96,334 |
|
| | | | | | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | STATEMENTS OF CASH FLOWS | | | | | | |
| | | For the Years Ended December 31, | | For the Years Ended December 31, |
| | | 2015 | | 2014 | | 2013 | | 2016 | | 2015 | | 2014 |
| | | (In Thousands) | | (In Thousands) |
| OPERATING ACTIVITIES | | | | | | | | | | | | |
| Net income | |
| $111,318 |
| |
| $96,334 |
| |
| $113,664 |
| |
| $96,744 |
| |
| $111,318 |
| |
| $96,334 |
|
| Adjustments to reconcile net income to net cash flow provided by operating activities: | | | | | | | | | | | | |
| Depreciation, amortization, and decommissioning, including nuclear fuel amortization | | 270,514 |
| | 254,199 |
| | 293,537 |
| | 224,879 |
| | 270,514 |
| | 254,199 |
|
| Deferred income taxes, investment tax credits, and non-current taxes accrued | | 200,797 |
| | 79,835 |
| | 29,996 |
| | 99,531 |
| | 200,797 |
| | 79,835 |
|
| Changes in assets and liabilities: | | |
| | |
| | |
| | |
| | |
| | |
|
| Receivables | | 5,879 |
| | 37,345 |
| | (29,226 | ) | | (15,846 | ) | | 5,879 |
| | 37,345 |
|
| Accounts payable | | (352 | ) | | (6,372 | ) | | 6,685 |
| | 2,720 |
| | (352 | ) | | (6,372 | ) |
| Prepaid taxes and taxes accrued | | (32,594 | ) | | 12,146 |
| | (170,356 | ) | | (6,555 | ) | | (32,594 | ) | | 12,146 |
|
| Interest accrued | | (19,013 | ) | | 21,371 |
| | (3,794 | ) | | (134 | ) | | (19,013 | ) | | 21,371 |
|
| Other working capital accounts | | 13,576 |
| | (11,688 | ) | | 24,863 |
| | (15,470 | ) | | 13,576 |
| | (11,688 | ) |
| Other regulatory assets | | (4,565 | ) | | (64,262 | ) | | 79,345 |
| | (58,279 | ) | | (4,565 | ) | | (64,262 | ) |
| Pension and other postretirement liabilities | | (16,888 | ) | | 49,741 |
| | (63,206 | ) | | 5,586 |
| | (16,888 | ) | | 49,741 |
|
| Other assets and liabilities | | (26,136 | ) | | (40,384 | ) | | (1,870 | ) | | 8,763 |
| | (26,136 | ) | | (40,384 | ) |
| Net cash flow provided by operating activities | | 502,536 |
| | 428,265 |
| | 279,638 |
| | 341,939 |
| | 502,536 |
| | 428,265 |
|
| INVESTING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Construction expenditures | | (70,358 | ) | | (63,774 | ) | | (51,584 | ) | | (88,037 | ) | | (70,358 | ) | | (63,774 | ) |
| Allowance for equity funds used during construction | | 8,494 |
| | 5,069 |
| | 7,784 |
| | 7,944 |
| | 8,494 |
| | 5,069 |
|
| Nuclear fuel purchases | | (64,977 | ) | | (181,209 | ) | | (65,691 | ) | | (151,068 | ) | | (64,977 | ) | | (181,209 | ) |
| Proceeds from sale of nuclear fuel | | 57,681 |
| | 61,076 |
| | 26,522 |
| |
| Proceeds from the sale of nuclear fuel | | | 11,467 |
| | 57,681 |
| | 61,076 |
|
| Proceeds from nuclear decommissioning trust fund sales | | 390,371 |
| | 392,872 |
| | 215,467 |
| | 499,252 |
| | 390,371 |
| | 392,872 |
|
| Investment in nuclear decommissioning trust funds | | (421,220 | ) | | (424,814 | ) | | (247,042 | ) | | (534,083 | ) | | (421,220 | ) | | (424,814 | ) |
| Change in money pool receivable - net | | (37,553 | ) | | 6,850 |
| | 17,692 |
| |
| Changes in money pool receivable - net | | | 6,117 |
| | (37,553 | ) | | 6,850 |
|
| Litigation proceeds for reimbursement of spent nuclear fuel storage costs | | | 15,806 |
| | — |
| | — |
|
| Net cash flow used in investing activities | | (137,562 | ) | | (203,930 | ) | | (96,852 | ) | | (232,602 | ) | | (137,562 | ) | | (203,930 | ) |
| FINANCING ACTIVITIES | | |
| | |
| | |
| | |
| | |
| | |
|
| Proceeds from the issuance of long-term debt | | — |
| | — |
| | 85,000 |
| |
| Retirement of long-term debt | | (136,310 | ) | | (46,743 | ) | | (111,479 | ) | | (22,002 | ) | | (136,310 | ) | | (46,743 | ) |
| Changes in credit borrowings - net | | (20,404 | ) | | 20,404 |
| | (39,986 | ) | | 66,893 |
| | (20,404 | ) | | 20,404 |
|
| Common stock dividends and distributions | | (200,750 | ) | | (101,930 | ) | | (70,286 | ) | | (139,000 | ) | | (200,750 | ) | | (101,930 | ) |
| Other | | (28 | ) | | (29 | ) | | (2,515 | ) | | (26 | ) | | (28 | ) | | (29 | ) |
| Net cash flow used in financing activities | | (357,492 | ) | | (128,298 | ) | | (139,266 | ) | | (94,135 | ) | | (357,492 | ) | | (128,298 | ) |
| Net increase in cash and cash equivalents | | 7,482 |
| | 96,037 |
| | 43,520 |
| | 15,202 |
| | 7,482 |
| | 96,037 |
|
| Cash and cash equivalents at beginning of period | | 223,179 |
| | 127,142 |
| | 83,622 |
| | 230,661 |
| | 223,179 |
| | 127,142 |
|
| Cash and cash equivalents at end of period | |
| $230,661 |
| |
| $223,179 |
| |
| $127,142 |
| |
| $245,863 |
| |
| $230,661 |
| |
| $223,179 |
|
| SUPPLEMENTAL DISCLOSURE OF CASH FLOW INFORMATION: | | |
| | |
| | |
| | |
| | |
| | |
|
| Cash paid (received) during the period for: | | |
| | |
| | |
| | |
| | |
| | |
|
| Interest - net of amount capitalized | |
| $47,864 |
| |
| $27,834 |
| |
| $32,178 |
| |
| $36,152 |
| |
| $47,864 |
| |
| $27,834 |
|
| Income taxes | |
| ($114,092 | ) | |
| ($10,065 | ) | |
| $211,210 |
| |
| ($23,565 | ) | |
| ($114,092 | ) | |
| ($10,065 | ) |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | BALANCE SHEETS | ASSETS | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT ASSETS | | | | | | | | |
| Cash and cash equivalents: | | | | | | | | |
| Cash | |
| $8,681 |
| |
| $789 |
| |
| $786 |
| |
| $8,681 |
|
| Temporary cash investments | | 221,980 |
| | 222,390 |
| | 245,077 |
| | 221,980 |
|
| Total cash and cash equivalents | | 230,661 |
| | 223,179 |
| | 245,863 |
| | 230,661 |
|
| Accounts receivable: | | |
| | |
| | |
| | |
|
| Associated companies | | 93,724 |
| | 60,907 |
| | 104,390 |
| | 93,724 |
|
| Other | | 4,574 |
| | 5,717 |
| | 3,637 |
| | 4,574 |
|
| Total accounts receivable | | 98,298 |
| | 66,624 |
| | 108,027 |
| | 98,298 |
|
| Materials and supplies - at average cost | | 87,366 |
| | 80,049 |
| | 82,469 |
| | 87,366 |
|
| Deferred nuclear refueling outage costs | | 5,605 |
| | 26,580 |
| | 24,729 |
| | 5,605 |
|
| Prepayments and other | | 11,282 |
| | 2,312 |
| | 20,111 |
| | 11,282 |
|
| TOTAL | | 433,212 |
| | 398,744 |
| | 481,199 |
| | 433,212 |
|
| | | | | | | | | |
| OTHER PROPERTY AND INVESTMENTS | | |
| | |
| | |
| | |
|
| Decommissioning trust funds | | 701,460 |
| | 679,840 |
| | 780,496 |
| | 701,460 |
|
| TOTAL | | 701,460 |
| | 679,840 |
| | 780,496 |
| | 701,460 |
|
| | | | | | | | | |
| UTILITY PLANT | | |
| | |
| | |
| | |
|
| Electric | | 4,253,949 |
| | 4,244,902 |
| | 4,331,668 |
| | 4,253,949 |
|
| Property under capital lease | | 575,027 |
| | 573,784 |
| | 585,084 |
| | 575,027 |
|
| Construction work in progress | | 92,546 |
| | 50,382 |
| | 43,888 |
| | 92,546 |
|
| Nuclear fuel | | 183,706 |
| | 251,376 |
| | 259,635 |
| | 183,706 |
|
| TOTAL UTILITY PLANT | | 5,105,228 |
| | 5,120,444 |
| | 5,220,275 |
| | 5,105,228 |
|
| Less - accumulated depreciation and amortization | | 2,961,842 |
| | 2,819,688 |
| | 3,063,249 |
| | 2,961,842 |
|
| UTILITY PLANT - NET | | 2,143,386 |
| | 2,300,756 |
| | 2,157,026 |
| | 2,143,386 |
|
| | | | | | | | | |
| DEFERRED DEBITS AND OTHER ASSETS | | |
| | |
| | |
| | |
|
| Regulatory assets: | | |
| | |
| | |
| | |
|
| Regulatory asset for income taxes - net | | 98,230 |
| | 105,882 |
| | 93,127 |
| | 98,230 |
|
| Other regulatory assets | | 347,830 |
| | 335,613 |
| | 411,212 |
| | 347,830 |
|
| Other | | 4,757 |
| | 5,358 |
| | 4,652 |
| | 4,757 |
|
| TOTAL | | 450,817 |
| | 446,853 |
| | 508,991 |
| | 450,817 |
|
| | | | | | | | | |
| TOTAL ASSETS | |
| $3,728,875 |
| |
| $3,826,193 |
| |
| $3,927,712 |
| |
| $3,728,875 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | BALANCE SHEETS | LIABILITIES AND EQUITY | | | | | | |
| | | December 31, | | December 31, |
| | | 2015 | | 2014 | | 2016 | | 2015 |
| | | (In Thousands) | | (In Thousands) |
| | | | | | | | | |
| CURRENT LIABILITIES | | | | | | | | |
| Currently maturing long-term debt | |
| $2 |
| |
| $76,310 |
| |
| $50,003 |
| |
| $2 |
|
| Short-term borrowings | | — |
| | 20,404 |
| | 66,893 |
| | — |
|
| Accounts payable: | | |
| | |
| | |
| | |
|
| Associated companies | | 7,391 |
| | 6,252 |
| | 5,843 |
| | 7,391 |
|
| Other | | 34,010 |
| | 33,096 |
| | 50,558 |
| | 34,010 |
|
| Taxes accrued | | — |
| | 23,267 |
| |
| Accumulated deferred income taxes | | — |
| | 14,175 |
| |
| Interest accrued | | 14,183 |
| | 33,196 |
| | 14,049 |
| | 14,183 |
|
| Other | | 1,926 |
| | 2,365 |
| | 2,957 |
| | 1,926 |
|
| TOTAL | | 57,512 |
| | 209,065 |
| | 190,303 |
| | 57,512 |
|
| | | | | | | | | |
| NON-CURRENT LIABILITIES | | |
| | |
| | |
| | |
|
| Accumulated deferred income taxes and taxes accrued | | 1,019,075 |
| | 808,171 |
| | 1,112,865 |
| | 1,019,075 |
|
| Accumulated deferred investment tax credits | | 45,451 |
| | 49,313 |
| | 41,663 |
| | 45,451 |
|
| Other regulatory liabilities | | 337,424 |
| | 371,110 |
| | 370,862 |
| | 337,424 |
|
| Decommissioning | | 803,405 |
| | 757,918 |
| | 854,202 |
| | 803,405 |
|
| Pension and other postretirement liabilities | | 112,264 |
| | 129,152 |
| | 117,850 |
| | 112,264 |
|
| Long-term debt | | 572,665 |
| | 630,603 |
| | 501,129 |
| | 572,665 |
|
| Other | | — |
| | 350 |
| | 15 |
| | — |
|
| TOTAL | | 2,890,284 |
| | 2,746,617 |
| | 2,998,586 |
| | 2,890,284 |
|
| | | | | | | | | |
| Commitments and Contingencies | |
|
| |
|
| |
|
| |
|
|
| | | | | | | | | |
| COMMON EQUITY | | |
| | |
| | |
| | |
|
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2015 and 2014 | | 719,350 |
| | 789,350 |
| |
| Common stock, no par value, authorized 1,000,000 shares; issued and outstanding 789,350 shares in 2016 and 2015 | | | 679,350 |
| | 719,350 |
|
| Retained earnings | | 61,729 |
| | 81,161 |
| | 59,473 |
| | 61,729 |
|
| TOTAL | | 781,079 |
| | 870,511 |
| | 738,823 |
| | 781,079 |
|
| | | | | | | | | |
| TOTAL LIABILITIES AND EQUITY | |
| $3,728,875 |
| |
| $3,826,193 |
| |
| $3,927,712 |
| |
| $3,728,875 |
|
| | | | | | | | | |
| See Notes to Financial Statements. | | |
| | |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | STATEMENTS OF CHANGES IN COMMON EQUITY | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
| | | | | | | |
| | Common Equity | | | Common Equity | | |
| | Common Stock | | Retained Earnings | | Total | Common Stock | | Retained Earnings | | Total |
| | (In Thousands) | (In Thousands) |
| | | | | | | | | | | |
| Balance at December 31, 2012 |
| $789,350 |
| |
| $43,379 |
| |
| $832,729 |
| |
| Net income | — |
| | 113,664 |
| | 113,664 |
| |
| Common stock dividends | — |
| | (70,286 | ) | | (70,286 | ) | |
| Balance at December 31, 2013 |
| $789,350 |
| |
| $86,757 |
| |
| $876,107 |
|
| $789,350 |
| |
| $86,757 |
| |
| $876,107 |
|
| Net income | — |
| | 96,334 |
| | 96,334 |
| — |
| | 96,334 |
| | 96,334 |
|
| Common stock dividends | — |
| | (101,930 | ) | | (101,930 | ) | — |
| | (101,930 | ) | | (101,930 | ) |
| Balance at December 31, 2014 |
| $789,350 |
| |
| $81,161 |
| |
| $870,511 |
|
| $789,350 |
| |
| $81,161 |
| |
| $870,511 |
|
| Net income | — |
| | 111,318 |
| | 111,318 |
| — |
| | 111,318 |
| | 111,318 |
|
| Common stock dividends and distributions | (70,000 | ) | | (130,750 | ) | | (200,750 | ) | (70,000 | ) | | (130,750 | ) | | (200,750 | ) |
| Balance at December 31, 2015 |
| $719,350 |
| |
| $61,729 |
| |
| $781,079 |
|
| $719,350 |
| |
| $61,729 |
| |
| $781,079 |
|
| Net income | | — |
| | 96,744 |
| | 96,744 |
|
| Common stock dividends and distributions | | (40,000 | ) | | (99,000 | ) | | (139,000 | ) |
| Balance at December 31, 2016 | |
| $679,350 |
| |
| $59,473 |
| |
| $738,823 |
|
| | | | | | | | | | | |
| See Notes to Financial Statements. | |
| | |
| | |
| |
| | |
| | |
|
| | SYSTEM ENERGY RESOURCES, INC. | SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON | | | | | | | | | | | | | | | | | | | | |
| | 2015 | | 2014 | | 2013 | | 2012 | | 2011 | 2016 | | 2015 | | 2014 | | 2013 | | 2012 |
| | (Dollars In Thousands) | (Dollars In Thousands) |
| | | | | | | | | | | | | | | | | | | |
| Operating revenues |
| $632,405 |
| |
| $664,364 |
| |
| $735,089 |
| |
| $622,118 |
| |
| $563,411 |
|
| $548,291 |
| |
| $632,405 |
| |
| $664,364 |
| |
| $735,089 |
| |
| $622,118 |
|
| Net Income |
| $111,318 |
| |
| $96,334 |
| |
| $113,664 |
| |
| $111,866 |
| |
| $64,197 |
| |
| Net income | |
| $96,744 |
| |
| $111,318 |
| |
| $96,334 |
| |
| $113,664 |
| |
| $111,866 |
|
| Total assets |
| $3,728,875 |
| |
| $3,826,193 |
| |
| $3,537,414 |
| |
| $3,614,610 |
| |
| $3,234,793 |
|
| $3,927,712 |
| |
| $3,728,875 |
| |
| $3,826,193 |
| |
| $3,537,414 |
| |
| $3,614,610 |
|
| Long-term obligations (a) |
| $572,665 |
| |
| $630,603 |
| |
| $702,273 |
| |
| $663,039 |
| |
| $626,313 |
|
| $501,129 |
| |
| $572,665 |
| |
| $630,603 |
| |
| $702,273 |
| |
| $663,039 |
|
| Electric energy sales (GWh) | 10,547 |
| | 9,219 |
| | 9,794 |
| | 6,602 |
| | 9,293 |
| 5,384 |
| | 10,547 |
| | 9,219 |
| | 9,794 |
| | 6,602 |
|
| | | | | | | | | | | | | | | | | | | |
(a) Includes long-term debt (excluding currently maturing debt). |
Item 2. Properties
Information regarding the registrant’s properties is included in Part I. Item 1. - Entergy’s Business under the sections titled “Utility - Property and Other Generation Resources” and “Entergy Wholesale Commodities - Property” in this report.
Item 3. Legal Proceedings
Details of the registrant’s material environmental regulation and proceedings and other regulatory proceedings and litigation that are pending or those terminated in the fourth quarter of 20152016 are discussed in Part I. Item 1. - Entergy’s Business under the sections titled “Retail Rate Regulation,” “Environmental Regulation,” and “Litigation” and “Impairment of Long-LivedLong-lived Assets” in Note 1 14to the financial statements in this report.statements.
Item 4. Mine Safety Disclosures
Not applicable.
EXECUTIVE OFFICERS OF ENTERGY CORPORATION
Executive Officers
|
| | | | | | |
| Name | | Age | | Position | | Period |
| Leo P. Denault (a) | | 5657 | | 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 |
| | | | | | | |
| William M. Mohl (a) | | 5657 | | President, Entergy Wholesale Commodities | | 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 |
| | | | | | | |
| Theodore H. Bunting, Jr. (a) | | 5758 | | Group President Utility Operations of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, and Entergy Texas | | 2012-Present |
| | | | | President, Chief Executive Officer, and Director of System Energy | | 2014-Present |
| | | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2012-Present |
| | | | | 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 | | 2007-2012 |
|
| | | | | | |
| Name | | Age | | Position | | Period |
| A. Christopher Bakken, III (a) | | 55 | | Executive Vice President and Chief Nuclear Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, and System Energy | | 2016-Present |
| | | | Project Director, Hinkley Point C of EDF Energy | | 2009-2016 |
| | | | | | |
| Marcus V. Brown (a) | | 5455 | | Executive Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | Senior Vice President and General Counsel of Entergy Corporation, Entergy Arkansas, Entergy Gulf States Louisiana, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2012-2013 |
| | | | | Vice President and Deputy General Counsel of Entergy Services, Inc. | | 2009-2012 |
| | | | | Associate General Counsel of Entergy Services, Inc. | | 2007-2009 |
| | | | | | | |
| Andrew S. Marsh (a) | | 4445 | | Executive Vice President and Chief Financial Officer of Entergy Corporation | | 2013-Present |
| | | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2013-Present |
| | | | | Chief Financial Officer of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2014-Present |
| | | | | Vice President, System Planning of Entergy Services, Inc. | | 2010-2013 |
| | | | | Vice President, Planning and Financial Communications of Entergy Services, Inc. | | 2007-2010 |
| | | | | | | |
| Roderick K. West (a) | | 4748 | | Executive Vice President and of Entergy Corporation | | 2010-Present |
| | | | Chief Administrative Officer of Entergy Corporation | | 2010-Present2010-2016 |
| | | | | President and Chief Executive Officer of Entergy New Orleans | | 2007-2010 |
| | | | | Director of Entergy New Orleans | | 2005-2011 |
| | | | | | | |
| Paul D. Hinnenkamp (a) | | 5455 | | Senior Vice President and Chief Operating Officer of Entergy Corporation | | 2015-Present |
| | | | | Director of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas | | 2015-Present |
| | | | | Senior Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2015 |
| | | | | Vice President, Capital Project Management and Technology of Entergy Services, Inc. | | 2013-2015 |
| | | | | Vice President of Fossil Generation Development and Support of Entergy Services, Inc. | | 2010-2013 |
| | | | | | |
Timothy G. Mitchell (a) | | 57 | | Acting Chief Nuclear Officer of Entergy Corporation | | 2015-Present |
| | | | Senior Vice President, Chief Nuclear Officer of Entergy Arkansas, Entergy Louisiana, and System Energy | | 2015-Present |
| | | | Director of System Energy | | 2015-Present |
| | | | Senior Vice President, Nuclear Operations of Entergy Services, Inc. | | 2014-Present |
| | | | Chief Operating Officer, Nuclear Operations of Entergy Services, Inc. | | 2011-2014 |
| | | | Senior Vice President, Engineering and Technical Services of Entergy Services, Inc. | | 2009-2011 |
|
| | | | | | |
| Name | | Age | | Position | | Period |
| Alyson M. Mount (a) | | 4546 | | Senior Vice President and Chief Accounting Officer of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy | | 2012-Present |
| | | | | Vice President Corporate Controller of Entergy Services, Inc. | | 2010-2012 |
| | | | | Director, Corporate Reporting and Accounting Policy of Entergy Services, Inc. | | 2002-2010 |
| | | | | | | |
| Andrea Coughlin Rowley (a) | | 51 | | Senior Vice President, Human Resources of Entergy Corporation | | 2016-Present |
| | | | President and Chief Executive Officer of Advance/Evolve LLC | | 2013-2016 |
| | | | Vice President, Human Resources of Dover Corporation | | 2012-2013 |
| | | | | | |
| Donald W. Vinci (a) | | 5758 | | Executive Vice President and Chief Administrative Officer of Entergy Corporation | | 2016-Present |
| | | | Senior Vice President, Human Resources and Chief Diversity Officer of Entergy Corporation | | 2013-Present2013-2016 |
| | | | | Vice President, Human Capital Management of Entergy Services, Inc. | | 2013 |
| | | | | Vice President, Gas Distribution Business of Entergy Services, Inc. | | 2010-2013 |
| | | | | Vice President, Business Development of Entergy Services, Inc. | | 2008-2010 |
| |
| (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. |
Each officer of Entergy Corporation is elected yearly by the Board of Directors. Each officer’s age and title is provided as of December 31, 2015.2016.
PART II
Item 5. Market for Registrants’ Common Equity and Related Stockholder Matters
Entergy Corporation
The shares of Entergy Corporation’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’s common stock for each quarterly period in 20152016 and 20142015 were as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | High | | Low | | High | | Low | High | | Low | | High | | Low |
| | (In Dollars) | (In Dollars) |
| First | 90.33 | | 73.88 | | 67.02 | | 60.40 | 79.72 | | 65.38 | | 90.33 | | 73.88 |
| Second | 79.84 | | 69.06 | | 82.30 | | 66.41 | 81.36 | | 72.67 | | 79.84 | | 69.06 |
| Third | 74.09 | | 61.27 | | 82.48 | | 70.70 | 82.09 | | 75.99 | | 74.09 | | 61.27 |
| Fourth | 70.67 | | 63.90 | | 92.02 | | 76.51 | 76.56 | | 66.71 | | 70.67 | | 63.90 |
Consecutive quarterly cash dividends on common stock were paid to stockholders of Entergy Corporation in 20152016 and 2014.2015. Quarterly dividends of $0.83 per share were paid in 2014 through third quarter 2015. In fourth quarter 2015 and through third quarter 2016, dividends of $0.85 per share were paid. In fourth quarter 2016, dividends of $0.87 per share were paid.
As of January 31, 2016,2017, there were 28,79927,567 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) |
| | | | | | | | | | |
10/01/20152016 | -10/31/20152016 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
11/01/20152016 | -11/30/20152016 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
12/01/20152016 | -12/31/20152016 | | — |
| |
| $— |
| | — |
| |
| $350,052,918 |
|
| Total | | | — |
| |
| $— |
| | — |
| | |
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, the Board has authorized share repurchase programs to enable opportunistic purchases in response to market conditions. In October 2010 the Board granted authority for a $500 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 2015,2016, Entergy withheld 35,47319,399 shares of its common stock at $88.83$68.09 per share, 40,050 shares of its common
stock at $88.15 per share, 42,70636,439 shares of its common stock at $87.51$70.58 per share, and 36,72182,619 shares of its common stock at $88.67$71.60 per share to pay income taxes due upon vesting of restricted stock granted and payout of performance unit payoutunits 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 relates only to the $500 million plan 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. |
Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy
There is no market for the common stock of Entergy Corporation’s wholly owned subsidiaries. Cash dividends on common stock paid by the Registrant Subsidiaries during 20152016 and 2014,2015, were as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 |
| | (In Millions) | (In Millions) |
| Entergy Arkansas |
| $— |
| |
| $10.0 |
|
| $— |
| |
| $— |
|
| Entergy Louisiana |
| $226.0 |
| |
| $487.5 |
|
| $285.5 |
| |
| $226.0 |
|
| Entergy Mississippi |
| $40.0 |
| |
| $61.4 |
|
| $24.0 |
| |
| $40.0 |
|
| Entergy New Orleans |
| $7.3 |
| |
| $6.0 |
|
| $18.7 |
| |
| $7.3 |
|
| Entergy Texas |
| $— |
| |
| $70.0 |
|
| $— |
| |
| $— |
|
| System Energy |
| $200.8 |
| |
| $101.9 |
|
| $139.0 |
| |
| $200.8 |
|
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.
Item 6. Selected Financial Data
Refer to “SELECTED FINANCIAL DATA - FIVE-YEAR COMPARISON OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.” which follow each company’s financial statements in this report, for information with respect to selected financial data and certain operating statistics.
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES, ENTERGY ARKANSAS, INC. AND SUBSIDIARIES, ENTERGY LOUISIANA, LLC AND SUBSIDIARIES, ENTERGY MISSISSIPPI, INC., ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES, ENTERGY TEXAS, INC. AND SUBSIDIARIES, and SYSTEM ENERGY RESOURCES, INC.”
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Refer to “MANAGEMENT’S FINANCIAL DISCUSSION AND ANALYSIS OF ENTERGY CORPORATION AND SUBSIDIARIES - Market and Credit Risk Sensitive Instruments.”
Item 8. Financial Statements and Supplementary Data
Refer to “TABLE OF CONTENTS - Entergy Corporation, Entergy Arkansas, Inc., Entergy Louisiana, LLC, Entergy Mississippi, Inc., Entergy New Orleans, Inc., Entergy Texas, Inc., and System Energy Resources, Inc.”
Item 9. Changes In and Disagreements With Accountants On Accounting and Financial Disclosure
No event that would be described in response to this item has occurred with respect to Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, or System Energy.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2015,2016, evaluations were performed under the supervision and with the participation of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) management, including their respective Principal Executive Officers (PEO) and Principal Financial Officers (PFO). The evaluations assessed the effectiveness of the Registrants’ disclosure controls and procedures. Based on the evaluations, each PEO and PFO has concluded that, as to the Registrant or Registrants for which they serve as PEO or PFO, the Registrant’s or 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’s or Registrants’ disclosure controls and procedures are also effective in reasonably assuring that such information is accumulated and communicated to the Registrant’s or Registrants’ management, including their respective PEOs and PFOs, as appropriate to allow timely decisions regarding required disclosure.
Internal Control over Financial Reporting
(Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
The managements of Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy (individually “Registrant” and collectively the “Registrants”) are responsible for establishing and maintaining adequate internal control over financial reporting for the Registrants. Each Registrant’s internal control system is designed to provide reasonable assurance regarding the preparation and fair presentation of each Registrant’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’s management assessed the effectiveness of each Registrant’s internal control over financial reporting as of December 31, 2015.2016. In making this assessment, each Registrant’s management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control - Integrated Framework. The 2013 COSO Framework was utilized for management’s assessment.
Based on each management’s assessment and the criteria set forth by the 2013 COSO Framework, each Registrant’s management believes that each Registrant maintained effective internal control over financial reporting as of December 31, 2015.2016.
The report of Deloitte & Touche LLP, Entergy Corporation’s independent registered public accounting firm, regarding Entergy Corporation’s internal control over financial reporting is included herein. The report of Deloitte & Touche LLP is not applicable to Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy because these Registrants are non-accelerated filers.
Changes in Internal Controls over Financial Reporting
Under the supervision and with the participation of each Registrant’s management, including its respective PEO and PFO, each Registrant evaluated changes in internal control over financial reporting that occurred during the quarter ended December 31, 20152016 and found no change that has materially affected, or is reasonably likely to materially affect, internal control over financial reporting.
Attestation Report of Registered Public Accounting Firm
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, 2015,2016, based on criteria established in Internal Control -Integrated Framework (2013) 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 Item 9A, 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, 2015,2016, based on the criteria established in Internal Control -Integrated Framework (2013) 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 of the Corporation as of and for the year ended December 31, 20152016 and our report dated February 25, 201624, 2017 expressed an unqualified opinion on those consolidated financial statements.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
PART III
Item 10. Directors and Executive Officers of the Registrants (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas)
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 6, 2016,5, 2017, 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.
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| | | | | | |
| Name | | Age | | Position | | Period |
| ENTERGY ARKANSAS, INC. |
| | | | | | | |
| Directors | | | | | | |
Hugh T. McDonaldRichard C. Riley | | 5754 | | President and Chief Executive Officer of Entergy Arkansas | | 2000-Present2016-Present |
| | | | | Director of Entergy Arkansas | | 2000-Present2016-Present |
| | | | Group Vice President, Customer Service and Operations of Entergy Arkansas | | 2015-2016 |
| | | | Vice President, Transmission of Entergy Services, Inc. | | 2010-2015 |
| | | | | | | |
| Theodore H. Bunting, Jr. | | | | 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. | | |
| Paul D. Hinnenkamp | | | | See information under the Entergy Corporation Officers Section in Part I. | | |
|
| | | | |
| Officers | | | | |
| A. Christopher Bakken, III | | See information under the Entergy Corporation Officers Section in Part I. | | |
| 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. | | |
| Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | 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. | | |
Timothy G. MitchellAlyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Alyson M. MountRichard C. Riley | | See information under the Entergy Arkansas Directors Section above. | | |
| Andrea Coughlin Rowley | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | 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. | | |
|
| | | | |
| ENTERGY LOUISIANA, LLC |
| Directors | | | | |
| Phillip R. May, Jr. | 5354 | DirectorPresident and Chief Executive Officer of Entergy Louisiana | | 2013-Present |
| | | President and Chief Executive OfficerDirector of 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. | | |
| Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
| Officers | | | | |
| A. Christopher Bakken, III | | See information under the Entergy Corporation Officers Section in Part I. | | |
| 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. | | |
| Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | 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. | | |
| Phillip R. May, Jr. | | See information under the Entergy Gulf States Louisiana Directors Section above. | | |
Timothy G. MitchellAlyson M. Mount | | See information under the Entergy Corporation Officers Section in Part I. | | |
Alyson M. MountAndrea Coughlin Rowley | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | 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. | | |
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| | | | |
| ENTERGY MISSISSIPPI, INC. |
| Directors | | | | |
| Haley R. Fisackerly | 5051 | President and Chief Executive Officer of Entergy Mississippi | | 2008-Present |
| | | Director of Entergy Mississippi | | 2008-Present |
| | | | | |
| Theodore H. Bunting, Jr. | | 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. | | |
| Paul D. Hinnenkamp | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
| 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. | | |
| 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. | | |
| Paul D. Hinnenkamp | | 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. | | |
| Andrea Coughlin Rowley | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | 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. | | |
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| | | | |
| ENTERGY NEW ORLEANS, INC. |
| Directors | | | | |
| Charles L. Rice, Jr. | 5152 | President and Chief Executive Officer of Entergy New Orleans | | 2010-Present |
| | | Director of Entergy New Orleans | | 2010-Present |
| | | Director, Utility Strategy of Entergy Services, Inc. | | 2009-2010 |
| | | Partner, Barrasso, Usdin, Kupperman, Freeman & Sarver, L.L.C. | | 2005-2009 |
| | | | | |
| Theodore H. Bunting, Jr. | | 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. | | |
| Paul D. Hinnenkamp | | See information under the Entergy Corporation Officers Section in Part I. | | |
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| | | | |
| 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. | | |
| Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | 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. | | |
| Andrea Coughlin Rowley | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | 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. | | |
|
| | | | |
| ENTERGY TEXAS, INC. |
| Directors | | | | |
| Sallie T. Rainer | 5455 | DirectorPresident and Chief Executive Officer of Entergy Texas | | 2012-Present |
| | | President and Chief Executive OfficerDirector 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. | | |
| Andrew S. Marsh | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | 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. | | |
| Leo P. Denault | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Paul D. Hinnenkamp | | 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. | | |
| Andrea Coughlin Rowley | | See information under the Entergy Corporation Officers Section in Part I. | | |
| Donald W. Vinci | | 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 common stockholder with the exception of the directors and officers of Entergy Louisiana, LLC, who are elected yearly to serve by the unanimous consent of the sole common membership owner, Entergy Utility Holding Company, LLC. Entergy Corporation’s directors are elected annually at the annual meeting of shareholders. Entergy Corporation’s officers are elected at the annual organizational meeting of the Board of Directors.
Corporate Governance Guidelines and Committee Charters
Each of the Audit, Corporate Governance, and Personnel Committees of Entergy Corporation’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’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’s Board of Directors:
Steven V. WilkinsonPatrick J. Condon (Chairman)
Maureen S. Bateman
Patrick J. Condon
Philip L. Frederickson
Blanche L. Lincoln
Karen A. Puckett
All Audit Committee members are independent. In addition to the general independence requirements, all Audit Committee members must meet the heightened independence standards imposed by the SEC and NYSE. All Audit Committee members possess the level of financial literacy and accounting or related financial management expertise required by the NYSE rules. The Board has determined that each of Patrick J. Condon and Philip L. Frederickson and Steven V. Wilkinson is an “audit committee financial expert” as such term is defined by the rules of the SEC.
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’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’s omnibus code of integrity under which Entergy operates called the Code of Entegrity as well as system policies. All employees are requiredexpected 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’s website (www.entergy.com) or upon written request.
Source of Nominations to the Board of Directors; Nominating Procedure
The Corporate Governance Committee will consider director candidates recommended by Entergy Corporation’s shareholders. Shareholders wishing to recommend a candidate to the Corporate Governance Committee should do so by submitting the recommendation in writing to Entergy Corporation’s Secretary at 639 Loyola Avenue, P.O. Box 61000, New Orleans, LA 70161, and it will be forwarded to the Corporate Governance Committee members for their consideration. Any recommendation should include:
the number of shares of Entergy Corporation held by the shareholder;
the name and address of the candidate;
a brief biographical description of the candidate, including his or her occupation for at least the last five years, and a statement of the qualifications of the candidate, taking into account the qualification requirements set forth above; and
the candidate’s signed consent to serve as a director if elected and to be named in the Proxy Statement.
Once the Corporate Governance Committee receives the recommendation, it may request additional information from the candidate about the candidate’s independence, qualifications, and other information that would assist the Corporate Governance Committee in evaluating the candidate, as well as certain information that must be disclosed about the candidate in the Proxy Statement, if nominated. The Corporate Governance Committee will apply the same standards in considering director candidates recommended by shareholders as it applies to other candidates.
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 6, 2016,5, 2017, under the heading “Section 16(a) Beneficial Ownership Reporting Compliance,” which information is incorporated herein by reference.
Item 11. Executive Compensation
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 LOUISIANA, ENTERGY MISSISSIPPI, ENTERGY NEW ORLEANS, AND ENTERGY TEXAS
COMPENSATION DISCUSSION AND ANALYSIS
In this section, the compensation earned by the following Named Executive Officers in 20152016 is discussed. Each officer’s title is provided as of December 31, 2015.2016.
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| |
Name(1) | Title |
Theodore H. Bunting, Jr.A. Christopher Bakken, III(2) | GroupExecutive Vice President Utility Operationsand Chief Nuclear Officer |
| Leo P. Denault | Chairman of the Board and Chief Executive Officer |
| Marcus V. Brown | Executive Vice President and General Counsel |
| Haley R. Fisackerly | President and Chief Executive Officer, Entergy Mississippi |
| Andrew S. Marsh | Executive Vice President and Chief Financial Officer Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas |
| Phillip R. May, Jr. | President and Chief Executive Officer, Entergy Louisiana |
Hugh T. McDonald(3) | Former President and Chief Executive Officer, Entergy Arkansas |
| Sallie T. Rainer | President and Chief Executive Officer, Entergy Texas |
| Charles L. Rice, Jr. | President and Chief Executive Officer, Entergy New Orleans |
Richard C. Riley (3) | President and Chief Executive Officer, Entergy Arkansas |
| Roderick K. West | Executive Vice President and Chief Administrative Officer |
| |
| (1) | Messrs. Bakken, Brown, Denault, Marsh, and West hold the positions referenced above as executive officers |
Messrs. Bunting, Denault, Marsh, and Mr. West hold the positions referenced above as executive officers of Entergy Corporation and are members of Entergy Corporation’s Office of the Chief Executive. No additional compensation was paid in 20152016 to any of these officers for their service as Named Executive Officers of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, or Entergy Texas (the “Subsidiaries”).
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| (2) | Mr. Bakken joined Entergy as Chief Nuclear Officer in April 2016. |
| |
| (3) | Mr. McDonald is included in the Executive Compensation section of this Form 10-K because he served as President and Chief Executive Officer, Entergy Arkansas for a portion of 2016. Mr. Riley succeeded Mr. McDonald as President and Chief Executive Officer, Entergy Arkansas in May 2016. |
CD&A Highlights
Executive Compensation Programs and Practices
Entergy Corporation regularly reviews its executive compensation programs to align them with commonly viewed best practices in the market. Following are some highlights of Entergy Corporation’s executive compensation practices:
Compensation Governance Best Practices:
What Entergy Corporation Does
RequiresRequire a “double trigger” for severance payments or equity acceleration in the event of a change in control
MaintainsMaintain a “clawback” policy that goes beyond Sarbanes-Oxley requirements
CapsCap the maximum payout at 200% of target under the Long-Term Performance Unit Program and under the Annual Incentive Plan for members of the Office of the Chief Executive
RequiresRequire minimum vesting periods for equity based awards
Targets theTarget long-term compensation mix to give more weight to performance units than to time-basedservice-based restricted stock and stock options combined
SettlesSettle 100% of long-term performance unit payoutsunits in shares of Entergy Corporation stock
RequiresRequire 6 times base salary stock ownership for Entergy Corporation’s Chief Executive Officer and 1 to 3 times base salary for other executive officers
Require executives to hold substantially all equity compensation received from Entergy Corporation until stock ownership guidelines are met
ProhibitsProhibit directors and officers from pledging or entering into hedging or other derivative transactions with respect to their Entergy Corporation shares
MitigatesMitigate undue risk taking in compensation programs
SubjectsSubject executive officer equity grants to non-compete and non-solicitation covenants
What Entergy Corporation Doesn’t Do
No 280(G)280G tax “gross up” payments in the event of a change in control
No tax “gross up” payments on any executive perquisites, other than relocation benefits available to all eligible employees, and club dues for some of the Named Executive Officers
No option repricing or cash buy-outs for underwater options under the equity plans
No agreements providing for severance payments to executive officers that exceed 2.99 times annual base salary and annual incentive awards without shareholder approval
No unusual or excessive perquisites
New officers are excluded from participation in the System Executive Retirement Plan
No grants of supplemental service credit forto newly-hired officers under any of Entergy Corporation’s non-qualified retirement plans
Entergy Corporation’s Pay for Performance Philosophy
Entergy Corporation’s executive compensation programs are based on a philosophy of pay-for-performancepay for performance that is embodied in the design of its annual and long-term incentive plans. In keepingEntergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a significant role in its ability to drive strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of operational financial metrics that are deemed by the Personnel Committee to be consistent with this philosophy approximately 85%the overall goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation. The long-term incentive programs further align the interests of Entergy Corporation executives and its shareholders by directly tying the value of the annual target compensationequity awards granted to executives under these programs to Entergy Corporation’s stock price performance and total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation’s Chief Executive Officer is “at risk,” equity or performance-based compensation.stakeholders, including its shareholders, customers, employees, and communities.
2015
2016 Incentive Pay Outcomes
Entergy Corporation believes that the 2015The 2016 incentive pay outcomes for Entergy Corporation’sthe Named Executive Officers demonstrated the application of itsEntergy Corporation’s pay for performance philosophy.
Annual Incentive Plan Awards
Awards under Entergy Corporation’sthe Executive Annual Incentive Plan or Annual Incentive Plan are tied to Entergy Corporation’s financial and operational performance through the Entergy Achievement Multiplier (EAM), which is the
performance metric used to determine the maximum funding available for awards under the plan. The 20152016 EAM was determined based in equal part on theEntergy Corporation’s success in achieving Entergy Corporation’sits operational earnings per share (EPS) and operational operating cash flow (OCF) goals set at the beginning of the year. These goals were approved by the Personnel Committee 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.
2016 Annual Incentive Program Payout.For 2015,2016, the Personnel Committee, based on a recommendation of the Finance Committee, determined that management exceeded its operational EPSearnings per share goal of $5.50$5.35 per share by $0.50 and exceeded$1.76, but fell short of its operational OCFoperating cash flow goal of $2.755$3.180 billion by $591approximately $176 million. Based on the targets and ranges previously established by the Committee, these results would have led toresulted in a calculated EAM of 184%133%. However,This determined the Committee determined that it was appropriate to adjustmaximum funding level for the reported results downward, for purposes of evaluating management’s degree of success in achieving its financial objectives for 2015, to reflect (i) amounts that had been included in both the financial plan, and targets related tofor the anticipated effect of an adverse litigation outcome that did not materialize in the year, and (ii) certain beneficial effects on operational EPS and OCF resulting from impairments that occurred with respect to certainNamed Executive Officers who are members of the wholesale nuclear generating plants in 2015. Following these adjustments,Office of the Committee determinedChief Executive, the Entergy Achievement Multipliermaximum award, as a percentage of target that could be received by them, subject to downward adjustment based on individual performance. Individual awards under the Annual Incentive Plan for 2015 to be 156%.
For members of Entergy Corporation’s Office of the Chief Executive, individual awards under the Annual Incentive Plan are determined by the Personnel Committee. In determiningAfter considering individual executive officer awards,performance, the Personnel Committee exercised its discretion to reduce awards to all membersapproved a payout of the Office133% of thetarget for Entergy Corporation’s Chief Executive because it determined that despite Entergy Corporation’s strong financial performance in relationOfficer and payouts ranging from 100% to the goals set at the beginning of the year and management’s success executing on Entergy Corporation’s strategies in 2015, management had not fully met the Board’s expectations with respect to certain aspects of operational performance. In determining the extent of this adjustment for individual officers, the Committee took into account the officer’s key accountabilities and accomplishments and individual performance executing on Entergy Corporation’s strategies. This resulted in payouts that ranged from 115% of target to 153%130% of target for the Named Executive Officers who are members of Entergy Corporation’sthe Office of the Chief Executive.
After the Entergy Achievement MultiplierEAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the Named Executive officers who are not members of the OCEOffice of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 153%60% of target to 200%125% of target for the Named Executive Officers who are not members of Entergy Corporation’s Office of the Chief Executive.
Long-Term Incentives
Long-Term Performance Unit Program Payouts
Long term incentives consist of three components to incentivize long-term value creation - performance units, stock options, and restricted stock. Performance under the Long-Term Performance Unit Program 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. Payouts, if any, are based solely on relative performance. Although Entergy Corporation had strong relativeCorporation’s total shareholder return for 2014, its total shareholder return did not compare favorablyperformance in relation to its peers and are not subject to adjustment by the Personnel Committee. Entergy Corporation also uses stock options, which reward increases in the Philadelphia Utility Index for 2013market value of its common stock, and 2015. As a result, forrestricted stock which is an effective retention mechanism.
Long-Term Performance Unit Program Payout. For the three year performance period ending in 2015,2016, Entergy Corporation’s total shareholder return was at the bottom ofin the third quartile, of the companies in the index, resulting in a payout of 25%36% of target for theits executive officers. Payouts were made 100% in shares of Entergy Corporation stock thatwhich are required to be held by executives until they satisfy the executive stock ownership guidelines.
What Entergy Corporation Pays and Why
Entergy Corporation’s 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 its annual and long-term incentive plans. Entergy Corporation believes the executive pay programs described in this section and in the accompanying tables have played a material role in its ability to drive
strong financial and operational results and to attract and retain a highly experienced and successful management team. The Annual Incentive Plan incentivizes and rewards the achievement of operational financial metrics that are deemed by the Personnel Committee to be consistent with the overall goals and strategic direction that the Board has approved for Entergy Corporation. The long-term incentive programs further align the interests of Entergy Corporation executives and its shareholders 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 its total shareholder return. By incentivizing officers to achieve important financial and operational objectives and create long-term shareholder value, these programs play a key role in creating sustainable value for the benefit of all of Entergy Corporation’s stakeholders including its shareholders, customers, employees and communities.
How Entergy Corporation Sets Target Pay
To develop a competitive compensation program, the Personnel Committee annually reviews compensation data from two sources:
SurveyUse of Competitive Data
The Personnel Committee uses published and private compensation survey data to develop marketplace compensation levels for Entergy Corporation’sthe executive officers. The data, which are compiled by Pay Governance LLC, the Committee’s independent compensation consultant, compare the current compensation opportunities provided to each of theEntergy Corporation’s 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) since the market for talent is broader than the utility sector. 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 cover hundreds of companies across a broad range of industries and approximately 60 investor-owned utility companies. In evaluating compensation levels against the survey data, the Committee considers only the aggregated survey data. The identities of the companies participating in the compensation survey data are not disclosed to, or considered by, the Committee in its decision-making process and, thus, are not considered material by the Committee.
The Committee uses this survey data to develop compensation opportunities that are designed to deliver total target compensation at approximately the 50th50th percentile of the surveyed companies in the aggregate. The survey data are the primary data used for purposes of assessing target compensation. As a result, Mr. Denault, Entergy Corporation’s Chief Executive Officer, is compensated at a higher level than the other Named Executive Officers, reflecting market practices that compensate chief executive officers at greater potential compensation levels with more pay “at risk” than other Named Executive Officers, due to the greater responsibilities and accountability required of a Chief Executive Officer. In most cases, the Committee considers its objectives to have been met if theEntergy Corporation’s Chief Executive Officer and the eight (8) other executive officers who constitute what Entergy Corporation refersis referred to as the Office of the Chief Executive each has a target compensation opportunity that falls within the range of 85% - 115% of the 50th percentile of the survey data. Promoted officers or officers who are new to their roles may be transitioned into the targeted market range over time. Actual compensation received by an individual officer may be above or below the targeted range based on an individual officer’s skills, performance, experience, and responsibilities, Entergy Corporation performance, and internal pay equity. For 2015,2016, the total target compensation of eachmost of the Named Executive Officers fell within the targeted range.range except there was one officer whose total targeted compensation was slightly above the targeted range, two officers whose total targeted compensation was slightly below the targeted range, based on skills, performance, experience and responsibilities, and internal pay equity, and one that was below the targeted range who is new to the role.
Proxy Analysis
Although the survey data described above are the primary data used in determining compensation, the Committee reviews data derived from the proxy statements of companies included in the Philadelphia Utility Index as an additional point of comparison. The proxy data are used to compare the compensation levels of the Named Executive Officers who are members of the Office of the Chief Executive with the compensation levels of the corresponding top five5 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, except with respect to the Chief Executive Officer and Chief Financial Officer, for whom comparable roles are used.statements. 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 from the 20152016 filings were compiled:
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| | | |
| Ÿ | AES Corporation | Ÿ | El Paso International |
| Ÿ | Ameren Corporation | Ÿ | EversourceEverSource Energy (formerly Northeast Utilities |
| Ÿ | American Electric Power Co. Inc. | Ÿ | Exelon Corporation |
| Ÿ | American Water Works | Ÿ | FirstEnergy Corporation |
| Ÿ | CenterPoint Energy Inc. | Ÿ | FirstEnergy CorporationNextEra Energy |
| Ÿ | Consolidated Edison Inc. | Ÿ | NextEra Energy |
Ÿ | Covanta Holding Corporation | Ÿ | PGEPG&E Corporation |
| Ÿ | Dominion Resources Inc. | Ÿ | Public Service Enterprise Group, Inc. |
| Ÿ | DTE Energy Company | Ÿ | Southern Company |
| Ÿ | Duke Energy Corporation | Ÿ | Xcel Energy |
| Ÿ | Edison International | | |
Executive Compensation Elements
The following table summarizes the elements of targettotal direct compensation (TDC) granted or paid to the executive officers under Entergy Corporation’s 2015the 2016 executive compensation program. The program uses a mix of fixed and variable compensation elements and provides alignment with both short- and long-term business goals through annual and long-term incentives. Incentives are designed to drive overall corporate performance, specific business unit strategies, and individual performance using performance and operational measures the Committee believes correlate to shareholder value and align with Entergy Corporation’s strategic vision and operating priorities. The Personnel Committee establishes the performance measures and ranges of performance for the variable compensation elements. An individual’s award is based primarily on corporate performance, market-based compensation levels, and individual performance.
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| Element | Key Characteristics | Why This Element Is Paid | How This Amount Is Determined | 20152016 Decisions |
| Base Salary | Fixed compensation component payable in cash. Reviewed annually and adjusted when appropriate. | Provides a base level of competitive cash compensation for executive talent. | Experience, job scope, market data, individual performance, and internal pay equity. | All of the Named Executive Officers, other than Mr. Bakken and Mr. Riley, received increases in their base salaries effective April 2016 ranging from 2.3%-5.4%2.5% to 4.5%.
In addition to his merit increase, Mr. Brown’s salary was increased by approximately 18% to reflect the additional responsibilities he assumed in 2016.
Mr. Fisackerly’s base salary was increased by 9.5% to reflect competitive market data.
Mr. Riley’s base salary was increased when he became President, Entergy Arkansas.
Mr. Bakken’s base salary was determined using market data. |
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| | | | |
| Element | Key Characteristics | Why This Element Is Paid | How This Amount Is Determined | 2016 Decisions |
| Annual Incentive Awards | Variable compensation component payable in cash based on performance against goals established annually. | Motivate and reward executives for performance on key financial and operational measures during the year. | Target opportunity is determined based on job scope, market data, and internal pay equity. For 2015,2016, awards were determined based on success in meeting operational earnings per share and operational operating cash flow targets, subject to downward adjustment at the discretion of the Personnel CommitteeCommittee’s discretion for members of Entergy Corporation'sthe Office of the Chief Executive andExecutive. | Mr. Denault's target annual incentive award for 20152016 was 125%135% of base salary, and target awards were in the range of 40%-70% to 70% of base salary for the other Named Executive Officers.
Strong operational and financial performance and a review of individual performance resulted in an award at 133% of target for Entergy Corporation’s Chief Executive Officer, and awards that ranged from 115%60% to 200%125% of target for the Named Executive Officers after adjustment for failure to fully meet the Board’s expectations with respect to certain aspects of operational performance, business unit |
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Element | Key Characteristics | Why This Element Is Paid | How This Amount Is Determined | 2015 Decisions |
| | | subject to adjustment for other Named Executive Officers based on business unit results as well as the individual officer's key accountabilities, accomplishments, and performance. | results, and the officer's key accountabilities, accomplishments, and performance in 2015.
Officers.
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Long-Term Performance Unit Program | Each performance unit equals the value of one share of Entergy CorporationCorporation’s common stock. Performance is measured at the end of a three-year performance period. Each unit also earns the equivalent of the dividends paid during the performance period. Performance units granted under the Long-Term Performance Unit Program are settled in shares of Entergy Corporation common stock rather than in cash.stock.
| Focuses the executive officers on building long-term shareholder value and increases executive officers’ ownership of Entergy Corporation common stock. | Payout based on Entergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index. | Performance unit grants for the 20152016 to 20172018 performance period represented approximately 40%39% of total target compensationTDC for Entergy Corporation’s Chief Executive Officer and approximately 22%21% to 31% for the other Named Executive Officers. Strong
Unfavorable relative total shareholder return in 2015 and 2016, partially offset by strong relative total shareholder return for 2014, combined with unfavorable relative TSR in 2013 and 2015, resulted in performance at the bottom ofin the third quartile for the 20132014 to 20152016 performance period, yielding a payout of 25%36% of target for the Named Executive Officers.Officers who are members of the Office of the Chief Executive. |
Stock Options | Non-qualified stock options are granted at fair market value, have a ten-year term, and vest over 3 years - 33 1/3% on each anniversary of the grant date. | Reward executives for absolute value creation and coupled with restricted stock provide competitive compensation, retain executive talent, and increase the executive officers’ ownership in Entergy Corporation’s common stock. | Job scope, market data, individual performance, and Entergy Corporation performance. | Stock options granted in 20152016 represented approximately 13% of total target compensationTDC for Entergy Corporation’s Chief Executive Officer and approximately 7% to 10% for the other Named Executive Officers. |
Restricted Stock Awards | Restricted stock awards vest over 3 years - 33 1/3% on each anniversary of the grant date, have voting rights, and accrue dividends during the vesting period. | Coupled with stock options, align interests of executives with long-term shareholder value, provide competitive compensation, retain executive talent, and increase the executive officers’ ownership of Entergy Corporation common stock. | Job scope, market data, individual performance, and Entergy Corporation performance. | Restricted stock granted in 20152016 represented approximately 13% of total target compensation for Entergy Corporation’s Chief Executive Officer and approximately 7% to- 10% for the other Named Executive Officers. |
Short-TermFixed Compensation
Base Salary
The Personnel Committee determines the base salaries for all of the Named Executive Officers who are members of the Office of the Chief Executive based on competitive compensation data, performance considerations, and advice provided by the Committee’s independent compensation consultant. For the other Named Executive
Officers, their salaries are established by their immediate supervisors using the same criteria. The Committee also considers internal pay equity; however, the Committee has not established any predetermined formula against which the base salary of one Named Executive Officer is measured against another officer or employee.
In 2015,2016, all of the Named Executive Officers, other than Mr. Bakken and Mr. Riley, received merit increases in their base salaries ranging from 2.3%approximately 2.5% to 5.4%4.5%. The increases in base salary were made in light of current economic conditions and the projected growth in executive salaries in 20152016 based on the market data previously discussed in this CD&A under “What Entergy Corporation Pays and Why - How Entergy Corporation Sets Target Pay,” as well as an internal pay equity comparison.
The following table sets forth the 20142015 and 20152016 base salaries for the Named Executive Officers. ChangesExcept as indicated below, changes in base salaries for 20152016 were effective in April.
| | | Named Executive Officer | | 2014 Base Salary | | 2015 Base Salary | | 2015 Base Salary | | 2016 Base Salary |
| Theodore H. Bunting, Jr. | | $596,960 | | $611,960 | |
A. Christopher Bakken, III(1) | | | $— | | $605,000 |
Marcus V. Brown(2) | | | $491,500 | | $605,000 |
| Leo P. Denault | | $1,110,000 | | $1,170,000 | | $1,170,000 | | $1,200,000 |
| Haley R. Fisackerly | | $302,934 | | $310,434 | |
Haley R. Fisackerly(3) | | | $310,434 | | $350,000 |
| Andrew S. Marsh | | $517,500 | | $537,892 | | $537,892 | | $559,408 |
| Phillip R. May, Jr. | | $338,250 | | $346,250 | | $346,250 | | $356,650 |
| Hugh T. McDonald | | $352,121 | | $360,121 | | $360,121 | | $360,121 |
| Sallie T. Rainer | | $298,275 | | $307,275 | | $307,275 | | $319,475 |
| Charles L. Rice, Jr. | | $262,287 | | $268,470 | | $268,470 | | $280,424 |
Richard C. Riley(4) | | | $306,168 | | $335,000 |
| Roderick K. West | | $628,044 | | $643,044 | | $643,044 | | $659,120 |
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| (1) | When Mr. Bakken joined Entergy in April 2016, his base salary was set at $605,000 based on competitive market data that placed him at the 50th percentile of the market data discussed above, as well as internal pay equity considerations. |
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| (2) | In April 2016, Mr. Brown received a merit increase of 4% to his base salary. In May 2016, Mr. Brown’s base salary was further adjusted to $605,000 following an external market competitive pay analysis to reflect his additional responsibilities when he assumed leadership of Entergy Corporation’s corporate communications and regulatory and governmental affairs groups, in addition to his leadership of Entergy Corporation’s legal department. |
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| (3) | In November 2016, Mr. Fisackerly’s base salary was increased by 9.5% after a review of his compensation in light of his experience relative to competitive market data. |
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| (4) | In May 2016, Mr. Riley’s salary was increased from $306,168 to $335,000 when he became President and Chief Executive Officer, Entergy Arkansas and assumed the increased responsibilities of that role. |
Variable Compensation
Short-Term Compensation
Annual Incentive Plan
Entergy Corporation includes performance-basedPerformance-based incentives are included in the Named Executive Officers’ compensation packages because itEntergy Corporation believes performance-based incentives encourage the Named Executive Officers to pursue objectives consistent with the overall Entergy Corporation goals and strategic direction that the Entergy Corporation Board has approved for Entergy Corporation.approved.
UnderEAM is the Annual Incentive Plan, Entergy Corporation uses a performance metric known as the Entergy Achievement Multiplierused to determine the maximum funding availablepercentage of target annual plan opportunities that will be paid each year to each Named Executive Officer who is a member of the Office of the Chief Executive under the plan, expressed as a percentageAnnual Incentive Plan. Once the EAM has been determined, individual awards for the Office of target.the Chief Executive members may be adjusted downward, but not upward, from the EAM at the Personnel Committee’s discretion, based on individual performance and other factors deemed relevant by the Personnel Committee. For 2015,2016, the target Annual Incentive Plan opportunities for each of the Named Executive Officers, expressed as a percentage of the officer’s base salary, were:
125%135% for Mr. Denault;
70% for Mr. Bunting,Bakken, Mr. Brown, Mr. Marsh, and Mr. West;
60% for Mr. May;
50% for Mr. McDonald; and
40% for Mr. Fisackerly, Ms. Rainer, Mr. Rice, and Mr. Rice.Riley.
The target opportunities established for these officers were comparable to the target opportunities historically set for these positions and levels of responsibility, except for theMr. Denault’s and Mr. Riley’s. Mr. Denault’s target opportunity for Mr. Denault’s, which was increased by the Personnel Committee from 120% to 125% of base salary for 2015set to align it with target opportunities of other chief executive officers based on the compensation survey data compiled by Pay Governance. Mr. Riley’s target was set consistent with market and internal pay equity. Target opportunities for the Named Executive Officers who are members of the Office of the Chief Executive are established by the Personnel Committee. TheseCommittee, and these Named Executive Officers may earn a maximum payout ranging from 0% to 200% of their target opportunity, calculated as described in the table below. The target awards for the other Named Executive Officers were set by their supervisor (subject to ultimate approval of Entergy Corporation’s Chief Executive Officer) who was allocated funds for such awards by the Chief Executive Officer based on business unit results.
Target award opportunities are set based on an executive officer’s position and executive management level within the Entergy organization. Executive management levels at Entergy range from Level 1 through Level 4. At
December 31,2015,31, 2016, Mr. Denault held a Level 1 position, Messrs. Bunting,Bakken, Brown, Marsh, and West held positions in Level 2, Mr. May held a Level 3 position, and the remaining Named Executive Officers held positions in Level 4. Accordingly, their respective incentive award opportunities differ from one another based on their management level and the external market data developed by the Committee’s independent compensation consultant.
Each year the Personnel Committee reviews the performance measures used to determine the Entergy Achievement Multiplier.EAM. In December 2014,2015, the Personnel Committee decided to retain for 2015 the performance measures used for determining the 2014 Entergy Achievement Multiplier. These measures were operational earnings per share (EPS) and operational operating cash flow, (OCF), with each measure weighted equally.equally, as the performance measures for determining the EAM. The Committee considered a variety of other potential measures, but determined that operational EPSearnings per share and OCFoperational operating cash flow continued to be the best metrics to use because, among other things, they are objective measures that Entergy CorporationCorporation’s investors consider to be important in evaluating Entergy Corporation’sits financial performance and because theEntergy Corporation’s goals in that regard are broadly communicated both internally and externally. This provides both discipline and transparency that the Committee believes are important objectives of any well designed incentive compensation plan.
The Personnel Committee also engages in a rigorous process each year to establish the targets for the Annual Incentive Plan with a goal of establishing target achievement levels that are consistent with Entergy Corporation’s strategy and business objectives for the upcoming year, as reflected in its financial plan, and sufficient to drive results that represent a high level of achievement, for Entergy Corporation, taking into consideration the applicable business environment and specific
challenges facing it. These targets are approved based on a comprehensive review by the full Board of Entergy Corporation’s financial plan, including changes in commodity market conditions and other key drivers of anticipated changes in performance from the preceding year. The Committee also reviews the effects on plan results of various risks and opportunities that are recognized at the time the plan is set, to assure that targets that are determined based on the plan reflect an appropriate balance of risks and opportunities. The Committee further confirms that the targets it approves are aligned with the earnings guidance that will be communicated to the financial markets, which assures that the internal targets setEntergy Corporation sets for purposes of theits incentive compensation plans are aligned with the external expectations set and communicated to Entergy Corporation’sits shareholders.
In January 2015,2016, after full Board review of management’s 20152016 financial plan for Entergy Corporation and engaging in the process discussed above, the Committee determined the Annual Incentive Plan targets to be used for purposes of determining Annual Incentive Plan awards for 2015.2016. In keeping with its past practice, the Committee also determined that for purposes of measuring performance against such targets, the Committee would exclude the effect on reported results of any major storms that may occur during the year. This exclusion was viewed by the Committee as appropriate because although Entergy Corporation includes estimates for minor storm events in its financial plan, it does not include estimates for a major storm event, such as a hurricane. The Committee also approved the exclusion from reported results of the outcome of a pending regulatory litigation matter, to the extent such outcome was not treated as a special item and excluded from operational results. Neither of these pre-approved exclusions ultimately resulted in any adjustment to the reported results.
In determining the targets to set for 2015,2016, the Committee reviewed anticipated drivers for operational EPSearnings per share and OCFoperational operating cash flow for 20152016 as set forth in Entergy Corporation’s financial plan. Operational EPS was expected to decline somewhat from 2014 due primarily to lower expectedUnder the plan, operational earnings from the EWC business as a result of substantially lower wholesale power prices and the absence of revenue from the Vermont Yankee, which shut down at the end of 2014, partially offset by expected Utility sales growth and a lower anticipated tax rate in 2015. Operational OCF also wasper share were expected to decline from 20142015 results due primarily to among other things, higherthe significant impact on 2015 operational results of tax payments,benefits and, to a lesser extent, favorable weather, which were not anticipated to recur in 2016. Together, they accounted for $1.89 of operational earnings per share for 2015. Under the absenceplan, operational operating cash flow was also expected to decline slightly in 2016 from 2015 results due primarily to the timing of securitization proceeds receivedrecovery of certain fuel and purchased power costs in 2014 from Hurricane Isaac securitizations,the utility business.
After adjusting to eliminate the impact of weather and tax benefits, the cash effect of an anticipated adverse litigation outcome. Based on this review, the Personnel Committee set the operational EPS and OCF2016 plan targets for operational earnings per share required management to achieve strong growth in utility operational earnings and modest growth in Entergy Wholesale Commodities operational earnings, despite an expectation for further declines in wholesale energy and capacity prices. While the resulting targets represented declines from 2015 whichoperational results, the Committee concluded, based on a careful review of the overall plan, that the targets aligned withderived from the plan challenged management appropriately to deliver strong growth in Entergy Corporation’s financial plancore business while continuing to manage the significant risks at Entergy Wholesale Commodities and its financial guidancerepresented an appropriate balancing of Entergy Corporation’s business risks and opportunities for 2015 that was subsequently communicated to investors.2016.
The following table shows the resulting Annual Incentive Plan targets established by the Personnel Committee in January 2015,2016, and 2015 results, as adjusted downward by the Committee as described below:2016 results:
Annual Incentive Plan Targets and Results
| | | | Performance Goals(1) | | Performance Goals(1) | |
| | Minimum | Target | Maximum | 2015 Results | Minimum | Target | Maximum | 2016 Results |
| Operational Earnings Per Share ($) | $4.95 | $5.50 | $6.05 | $6.00 | $4.82 | $5.35 | $5.88 | $7.11 |
| Operational Operating Cash Flow ($ billion) | $2.38 | $2.755 | $3.13 | $3.347 | $2.795 | $3.180 | $3.565 | $3.004 |
| Payout as % of Target | 25% | 100% | 200% | 156%(2) | |
| EAM as % of Target | | 25% | 100% | 200% | 133% |
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| (1) | Payouts for performance between minimum and target achievement levels and between target and maximum levels are calculated using straight-line interpolation. There is no payout for performance below minimum. |
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(2) | Reflects downward adjustment by Personnel Committee, as further described below. |
In January 2016,2017, the Finance and Personnel Committees jointly reviewed Entergy Corporation’s financial results against the performance objectives reflected in the table above. Management discussed with the committees Entergy Corporation’sCommittees the operational EPSearnings per share and OCFoperating cash flow results for 2015,2016, including primary factors explaining how those results compared to the 20152016 business plan and Annual Incentive Plan targets. Operational EPS for 2015earnings per share exceeded the target of $5.50operational earnings per share goal of $5.35 per share set at the beginning of the year by $0.50, while$1.76, but management fell short of achieving its operational OCF exceeded the targetoperating cash flow goal of $2.755$3.180 billion by approximately $592$176 million, leading to a calculated EAM of 184%133%. However,Operational results excluded the Committee determinedimpact of certain special items that it was appropriate to adjust the reported results downward, for purposes of evaluating management’s degree of success in achieving its financial objectives for 2015, to reflect (i) amounts that had been included in both the financial plan and targets related to the anticipated effect of an adverse litigation outcome that did not materialize in the year, and (ii) certain beneficial effects on operational EPS and OCF resulting from impairments that occurred with respect to certain of Entergy Corporation’s wholesale nuclear generating plants in 2015. The Committee considered it appropriate to exclude these beneficial effects from the reported results in keeping with the classification of the related impairments as a special item in 2015, which meant that they were excluded from operational results. Following these adjustments, the Committee determined the Entergy Achievement Multiplier for 2015 to be 156%. The Committee also reviewed the special items that had been excluded from as-reported EPS(GAAP) earnings per share and OCFoperating cash flow to determine operational EPSearnings per share and OCF, which includedoperational operating cash flow, including asset impairments and related write-offs at EWCEntergy Wholesale Commodities related to the 2015Entergy Corporation’s 2016 decision to close two nuclear generating plants, a gain on the sale by EWC of a natural gas-fired generating plant, and certain costs associated with nuclear plant closings. The Personnel Committee did not make any adjustments to the operational earnings per share and operating cash flow results to determine the EAM for 2016.
For members of Entergy Corporation’s Office of the Chief Executive, individual executive officer awards under the Annual Incentive Plan are determined by the Personnel Committee. In determining these individual executive officer awards under the Annual Incentive Plan, the Committee considered individual performance and, in particular, whether there were additional factors beyond those captured by the EAM measures that should be taken into account in determining whether to exercise negative discretion to reduce awards below the levels determined by the EAM. The Committee determinedIn determining the extent of negative discretion, if any, that in general, despite Entergy Corporation’s strong financial performance in relation to plan and management’s success executing on its strategies in 2015, a negative adjustment was appropriateit would exercise with respect to alleach Named Executive Officer who is a member of the Office of the Chief Executive, the Committee considered the executive's key accountabilities and accomplishments, time in role, and individual performance executing on Entergy Corporation’s strategies in 2016. This resulted in a payout equal to the EAM, or 133% of target, for the Chief Executive Officer and awards ranging from 100% of target to 130% of target for the other Named Executive Officers who are members of the Office of the Chief Executive as a result of management’s failure to fully meet the Board’s expectations with respect to certain aspects of Entergy Corporation’s operational performance. In determining the extent of this adjustment for individual officers, the Committee took into account the officer’s key accountabilities and accomplishments and individual performance executing on Entergy Corporation’s strategies. This resulted in payouts that ranged from 115% of target to 153% of target for Named Executive Officers who are members of Entergy Corporation’s Office of the Chief Executive.
After the Entergy Achievement MultiplierEAM was established to determine overall funding for the Annual Incentive Plan, Entergy Corporation’s Chief Executive Officer allocated incentive award funding to individual business units based on business unit results. Individual awards were determined for the remaining Named Executive Officers who are
not members of the Office of the Chief Executive by their immediate supervisor based on the individual officer’s key accountabilities, accomplishments, and performance. This resulted in payouts that ranged from 153%60% of target to 200%125% of target for the Named Executive Officers who are not members of Entergy’sthe Office of the Chief Executive.
Based on the foregoing evaluation of management performance, the Personnel Committee approved the following Annual Incentive Plan payouts to each Named Executive Officer for 2015:
2016:
| | | Named Executive Officer | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Base Salary | 2015 Annual Incentive Award | Base Salary | Target as Percentage of Base Salary | Payout as Percentage of Target | 2016 Annual Incentive Award |
| Theodore H. Bunting, Jr. | $611,960 | 70% | 107% | $655,409 | |
| A. Christopher Bakken, III | | $605,000 | 70% | 125% | $529,375 |
| Marcus V. Brown | | $605,000 | 70% | 130% | $550,550 |
| Leo P. Denault | $1,170,000 | 125% | 144% | $1,681,875 | $1,200,000 | 135% | 133% | $2,154,600 |
| Haley R. Fisackerly | $310,434 | 40% | 61% | $190,000 | $350,000 | 40% | 120% | $168,000 |
| Andrew S. Marsh | $537,892 | 70% | 95% | $508,308 | $559,408 | 70% | 130% | $509,061 |
| Phillip R. May, Jr. | $346,250 | 60% | 91% | $315,000 | $356,650 | 60% | 105% | $224,690 |
| Hugh T. McDonald | $360,121 | 50% | 100% | $360,000 | |
Hugh T. McDonald(1) | | $360,121 | 50% | 44% | $79,827 |
| Sallie T. Rainer | $307,275 | 40% | 62% | $190,000 | $319,475 | 40% | 120% | $153,348 |
| Charles L. Rice, Jr. | $268,470 | 40% | 64% | $173,000 | $280,424 | 40% | 60% | $67,302 |
| Richard C. Riley | | $335,000 | 40% | 125% | $167,500 |
| Roderick K. West | $643,044 | 70% | 95% | $607,677 | $659,120 | 70% | 100% | $461,384 |
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| (1) | Pursuant to the terms of the Annual Incentive Plan, Mr. McDonald received a pro-rated annual incentive award since he retired prior to the end of the performance year. |
Long-Term Incentive Compensation
Entergy Corporation’s goal for its long-term incentive compensation is to focus the executive officers on building shareholder value and to increase the executive officers’ ownership of Entergy CorporationCorporation’s common stock in order to more closely align their interest with those of Entergy Corporation’sits shareholders. In itsEntergy Corporation’s long-term incentive compensation program, Entergy Corporation usesprograms, a mix of performance units, restricted stock, and stock options.options are used. Performance units reward the Named Executive Officers on the basis of total shareholder return, which is a measure of stock price appreciation and dividend payments, in relation to the 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 to increase the value of Entergy Corporation’s common stock. In general, Entergy Corporation seeks to allocate the total value of long-term incentive compensation 60% to performance units and 40% to a combination of stock options and restricted stock, equally divided in value, based on the value the compensation model seeks to deliver. Awards for individual Named Executive Officers may vary from this target as a result of individual performance, promotions, and internal pay equity.
All of theThe performance units shares of restricted stock,for the 2014-2016 and stock options granted to the Named Executive Officers in 20152015-2017 performance periods were awarded under the 2011 Equity Ownership Plan and Long-Term Cash Incentive Plan (“2011(2011 Equity Ownership Plan”), exceptPlan) and the performance units for Mr. Marsh’sthe 2016-2018 performance period and all of the shares of restricted stock, unit grant described below which wasstock options, and restricted stock units granted to the Named Executive Officers in 2016 were granted pursuant to the 2015 Equity Ownership Plan (together(the 2015 Equity Ownership Plan, together with the 2011 Equity Ownership Plan, the “EquityEquity Ownership Plans”)Plans). The Equity Ownership Plans require both a change in control and an involuntary job loss or substantial diminution of duties (a “double trigger”) for the 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 unit represents the value of one share of Entergy CorporationCorporation’s common stock at the end of the three-year performance period, plus dividends accrued during the performance period. The Personnel Committee sets payout opportunities for the program at the outset of each performance period, and the program is structured to reward Named Executive Officers only if performance goals approved by the Personnel Committee are met. The Personnel Committee has no discretion to make awards if minimum performance goals are not achieved.
The performance units granted under the Long-Term Performance Unit Program and accrued dividends on any shares earned during the performance period are settled in shares of Entergy Corporation common stock rather than cash. All shares paid out under the Long-Term Performance Unit Program are required to be retained by the officers until applicable executive stock ownership requirements are met.
The Long-Term Performance Unit Program specifies a minimum, target, and maximum achievement level, the achievement of which will determine the number of performance units that may be earned by each participant. Entergy Corporation measures performance by assessing itsEntergy Corporation’s total shareholder return relative to the total shareholder return of the companies in the Philadelphia Utility Index, referredwhich Entergy Corporation refers to as Entergy Corporation’sits peer companies. The Personnel Committee identified the Philadelphia Utility Index as the appropriate industry peer group for this purpose 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 reflects theEntergy Corporation’s creation of shareholder value relative to other electric utilities over the performance 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 ranking of Entergy Corporation’s total shareholder return against the total shareholder return of the companies in the Philadelphia Utility Index.
Performance Unit Program Grants. At any given time, a participant in the Long-Term Performance Unit Program may be participating in up to three performance periods. Currently,During 2016, eligible participants arewere participating
in the 2014-2016, the 2015-2017, and the 2016-2018 performance periods. Subject to achievement of the applicable performance levels as described below, the Personnel Committee established the following target performance unit payout opportunities for each of the 2013-2015, 2014-2016, 2015-2017, and 2015-20172016-2018 performance periods.
| | | Named Executive Officer | 2013-2015 Target Opportunity | 2014-2016 Target Opportunity | 2015-2017 Target Opportunity | 2014-2016 Target Opportunity | 2015-2017 Target Opportunity | 2016-2018 Target Opportunity |
| Theodore H. Bunting, Jr. | 7,600 | 9,400 | 6,550 | |
Leo P. Denault(1) | 37,156 | 40,000 | 33,100 | |
A. Christopher Bakken, III (1) | | — | 3,639 | 7,289 |
| Marcus V. Brown | | 9,400 | 6,550 | 8,200 |
| Leo P. Denault | | 40,000 | 33,100 | 41,700 |
| Haley R. Fisackerly | 1,900 | 2,200 | 1,450 | 2,200 | 1,450 | 1,800 |
Andrew S. Marsh(1) | 7,442 | 9,400 | 6,550 | |
Phillip R. May, Jr.(1) | 2,969 | 3,100 | 2,050 | |
| Hugh T. McDonald | 1,900 | 2,200 | 1,450 | |
| Andrew S. Marsh | | 9,400 | 6,550 | 8,200 |
| Phillip R. May, Jr. | | 3,100 | 2,050 | 2,700 |
Hugh T. McDonald(2) | | 1,711 | 644 | — |
| Sallie T. Rainer | 1,900 | 2,200 | 1,450 | 2,200 | 1,450 | 1,800 |
| Charles L. Rice, Jr. | 1,900 | 2,200 | 1,450 | 2,200 | 1,450 | 1,800 |
| Richard C. Riley | | 2,200 | 1,450 | 1,800 |
| Roderick K. West | 7,600 | 9,400 | 6,550 | 9,400 | 6,550 | 8,200 |
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| (1) | Messrs. Denault, Marsh and MayAs a new hire in 2016, Mr. Bakken did not participate in the 2014-2016 performance period, but received pro-rated awardstarget award opportunities for the 2013-20152015-2017 and 2016-2018 performance cycles asperiods. |
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| (2) | In light of his anticipated retirement in May 2016, Mr. McDonald received a result of their promotions in 2013.pro-rated target award opportunity for 2014-2016 and 2015-2017 and did not receive award opportunities for the 2016-2018 performance period. |
For the 2013 - 2015 and 2014 - 2016 performance cycles, theThe range of potential payouts for the 2014-2016, 2015-2017, and 2016-2018 performance periods under the program is shown below.
|
| | | | |
| Performance Level | Zero | Minimum | Target | Maximum |
| Total Shareholder Return | 4th Quartile | Bottom of Third Quartile | 50thMedian percentile
| Top Quartile |
| Payout | No Payout | Minimum Payout of 25% of target | 100% of target | 200% of Target |
There is no payout for performance that falls within the lowest quartile of performance of the peer companies. Payouts between minimum and target and between target and maximum are calculated by interpolating between the performance of the company in the bottom position of the third quartile and the median or between the median and the performance of the company at the bottom position of the top quartile of the peer companies, respectively. For top quartile performance, a maximum payout of 200% of target is earned.
For the 2015 - 20172015-2017 and 2016-2018 performance cycle,periods, there also is no payout for performance that falls within the lowest quartile of performance of the peer companies, and for top quartile performance a maximum payout of 200% of target is earned. However, payoutsPayouts between minimum and target and between target and maximum are calculated by interpolating between the performance of the company at the top of the fourth quartile of performance of the peer companies and the median or between the median and the performance of the company at the bottom position of the top quartile of performance of the peer companies, respectively.
Payout for the 2013-20152014-2016 Performance Period.Period. In January 2016,2017, the Committee reviewed Entergy Corporation’s total shareholder return for the 2013-20152014-2016 performance period in order to determine the payout to participants for the 2013-20152014-2016 performance period. The Committee compared Entergy Corporation’s total shareholder return against the total shareholder return of the companies that comprise the Philadelphia Utility Index, with the performance measures and range of potential payouts for the 2013-20152014-2016 performance period similar to the range of payoutsthat discussed above. As recommended by the Finance Committee, the Personnel Committee determined that Entergy Corporation’s relative total shareholder return fell at the bottom ofin the third quartile, of the Philadelphia Utility Index for the 2013-2015 performance period, resulting in payouts to the Named Executive Officers of 25%36% of target. Payouts under the performance unit program are made in shares of Entergy Corporation common stock. For the 2013-20152014-2016 performance period, the following numbers of shares of Entergy Corporation common stock, including dividend equivalents were issued:
Mr. Denault - 10,644 shares,
Mr. Marsh - 2,132 shares,Mr. Bunting and Mr. West - 2,177 shares; |
| | | | |
| Named Executive Officer | 2014-2016 Target | Number of Shares Issued | Value of Shares Actually Issued(1) | Grant Date Fair Value |
A. Christopher Bakken(2) | — | — | $— | $— |
| Marcus V. Brown | 9,400 | 3,848 | $276,633 | $631,304 |
| Leo P. Denault | 40,000 | 16,375 | $1,177,199 | $2,686,400 |
| Haley R. Fisackerly | 2,200 | 900 | $64,701 | $147,752 |
| Andrew S. Marsh | 9,400 | 3,848 | $276,633 | $631,304 |
| Phillip R. May, Jr. | 3,100 | 1,269 | $91,228 | $208,196 |
Hugh T. McDonald(3) | 1,711 | 678 | $48,741 | $114,911 |
| Sallie T. Rainer | 2,200 | 900 | $64,701 | $147,752 |
| Charles L. Rice, Jr. | 2,200 | 900 | $64,701 | $147,752 |
| Richard C. Riley | 2,200 | 900 | $64,701 | $147,752 |
| Roderick K. West | 9,400 | 3,848 | $276,633 | $631,304 |
Mr. May - 849 shares; and
Mr. Fisackerly, Mr. McDonald, Ms. Rainer, and Mr. Rice - 544 shares
| |
| (1) | Value determined based on the closing price of Entergy Corporation’s common stock on January 18, 2017 ($71.89), the date the Personnel Committee certified the 2014-2016 performance period results. |
| |
| (2) | As a new hire in 2016, Mr. Bakken was not eligible to participate in the 2014-2016 performance period. |
| |
| (3) | Pursuant to the terms of the Long-Term Performance Unit Program, Mr. McDonald received a pro-rated award since he retired prior to the end of the performance period. |
Stock Options and Restricted Stock
Entergy Corporation grants stockStock options and restricted stock are granted as part of itsa long-term incentive program to itsthe executive officers. As previously discussed, the Personnel Committee considers several factors in determining the number of stock options and shares of restricted stock it will grant to the Named Executive Officers, including Entergy Corporation and individual performance, internal pay equity, prevailing market practice, targeted long-term value created by the use of stock options and restricted stock, and the potential dilutive effect of stock option and restricted stock grants. The Committee’s assessment of individual performance of each Named Executive Officer is the most important factor in determining the number of shares of restricted stock and stock options awarded, except with respect to the Chief Executive Officer for whom comparative market data is the most important factor. The Committee, in consultation with Entergy Corporation’s Chief Executive Officer, reviews each other Named Executive Officer’s performance, role and responsibilities, strengths, and developmental opportunities. Stock option and restricted stock awards for Entergy Corporation’s Chief Executive Officer are determined solely by the Personnel Committee on the basis of the same considerations. Mr. Denault’s 20152016 awards are comparable to historical awards granted to Entergy Corporation’s Chief Executive Officer and reflect the increaseddecreased stock price at the time of grant. For all equity awards, the Committee 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 2015.2016. The exercise price for each option was $89.90,$70.56, which was the closing price of Entergy’sEntergy Corporation’s common stock on the date of grant.
| | | Named Executive Officer | Stock Options | Shares of Restricted Stock | Stock Options | Shares of Restricted Stock |
| Theodore H. Bunting, Jr. | 22,600 | 4,800 | |
A. Christopher Bakken, III(1) | | — | — |
| Marcus V. Brown | | 45,000 | 6,400 |
| Leo P. Denault | 88,000 | 12,000 | 167,000 | 15,700 |
| Haley R. Fisackerly | 4,500 | 850 | 6,700 | 1,100 |
| Andrew S. Marsh | 24,000 | 5,000 | 45,000 | 6,400 |
| Phillip R. May, Jr. | 5,000 | 850 | 9,600 | 1,400 |
| Hugh T. McDonald | 3,600 | 700 | |
Hugh T. McDonald(2) | | — | — |
| Sallie T. Rainer | 3,800 | 750 | 6,700 | 1,100 |
| Charles L. Rice, Jr. | 4,500 | 750 | 6,700 | 1,100 |
| Richard C. Riley | | 4,700 | 1,050 |
| Roderick K. West | 23,000 | 4,700 | 41,000 | 6,000 |
| |
| (1) | Mr. Bakken was not eligible to receive stock options or restricted stock in 2016. |
| |
| (2) | In light of his upcoming retirement in May 2016, Mr. McDonald did not receive any stock options or restricted stock when the awards were determined in January 2016. |
Restricted Stock Units
Restricted stock units granted under the 2015 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 Entergy Corporationits common stock). Entergy Corporation occasionally grants restricted stock units 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 units lift at the end of the restricted period, and the restricted stock units are settled in shares of Entergy Corporation common stock. Restricted stock units are generally time-basedservice-based awards for which restrictions lift, subject to continued employment, generally over a two- to five-year period.
In August 2015,On April 6, 2016, in connection with the commencement of his employment as Chief Nuclear Officer, the Personnel Committee granted Mr. Marsh 21,100Bakken 30,000 restricted stock units. Mr. Marsh’sBakken’s award was made in part to recruit him to join Entergy, to offset compensation that Mr. Bakken forfeited by joining Entergy, in recognition of Mr. Marsh’s seniorhis leadership role and direction as Entergy Corporation’s Executive Vice President and Chief FinancialNuclear Officer to transform the nuclear fleet, and to encourage retention of his leadership in light of his marketability as a chief financialnuclear officer. The Committee noted, based on the advice of its independent consultant, that such grants are an effective means for retention.
Mr. Marsh’sBakken’s restricted stock units will vest and be settled in one installmentshares of Entergy Corporation’s common stock in three equal installments on August 3, 2020April 6, 2019, April 6, 2022, and April 6, 2025, provided that he remains continually employed as Chief Nuclear Officer or in a comparable position through each vesting date. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death, then he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following the date of his death or total disability. Additionally, if Mr. Bakken’s employment is terminated by his Entergy employer other than for cause on or before April 5, 2019, then he will vest in and be paid the 10,000 restricted stock units in which he otherwise would have vested on April 6, 2019, subject to earlier vestingMr. Bakken timely executing and not revoking a release of claims against Entergy Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon deathMr. Bakken’s termination of employment by his Entergy employer without cause or disability orby Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan) upon termination of employment by. Otherwise, if Mr. Marsh with good reasonBakken voluntarily resigns or a termination of employment by Entergy without cause.is terminated, he will forfeit all unvested stock units.
Benefits and Perquisites
Entergy’s Named Executive Officers are eligible to participate in or receive the following benefits:
|
| |
| Plan Type | Description |
| Retirement Plans | Entergy Corporation-sponsored:
-DefinedEntergy Retirement Plan - a tax-qualified final average pay defined benefit pension plan a tax qualified final average pay that covers a broad agroupgroup of employees;employees hired before July 1, 2014.
-PensionCash Balance Plan - a tax-qualified cash balance defined benefit retirement plan that covers a broad group of employees hired on or after July 1, 2014.
Pension Equalization Plan - a non-qualified pension restoration plan for a select group of management or highly compensated employees who participate in the Entergy Retirement Plan. Cash Balance Equalization Plan - a non-qualified restoration plan; andplan for a select group of management or highly compensated employees who participate in the Cash Balance Plan. -SystemSystem Executive Retirement Plan - a non-qualified supplemental retirement plan.plan for individuals who became executive officers before July 1, 2014.
See the 20152016 Pension Benefits Table for additional information regarding the operation of the plans described above. |
| Savings Plan | Entergy Corporation-sponsored 401(k) Savings Plan that covers a broad group of employees. |
| Health & Welfare Benefits | Medical, dental, and vision coverage, life and accidental death and dismemberment insurance, business travel accident 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. |
20152016 Perquisites | Corporate aircraft usage, annual physical exams, relocation assistance, and event tickets. The Office of the Chief Executive members do not receive tax gross ups on any benefits, except for relocation assistance.
Named Executive Officers who are not members of the Office of the Chief Executive also were provided in 20152016 with club dues, housing allowances, where appropriate, and tax gross up paymentpayments on some perquisites.
For additional information regarding perquisites, see the “All Other Compensation” column in the 20152016 Summary Compensation.Compensation Table. |
| Deferred Compensation | The Named Executive Officers are eligible to defer up to 100% of their base salary and Annual Incentive Plan awards into the Entergy Corporation-sponsored Executive Deferred Compensation PlanPlan. |
| Executive Disability Plan | Eligible individuals who become disabled under the terms of the plan are eligible for 65% of the difference between their base salary and $276,923 (i.e. the base salary that produces the maximum $15,000 monthly disability payment under the general long-term disability plan). |
Entergy Corporation provides these benefits to its Named Executive Officers as part of providing a competitive executive compensation program and because it believes that these benefits are important retention and recruitment tools since many, if not all, of the companies with which Entergy Corporation competes for executive talent provide similar arrangements to their senior executive officers.
Agreements
Compensation Arrangements
Mr. Bakken’s Employment
In connection with the commencement of his employment, Mr. Bakken received a sign-on bonus of $650,000 and Post-Termination Plansreceived a grant of 30,000 restricted stock units on April 6, 2016, the terms of which are previously described. Mr. Bakken is also eligible for certain relocation benefits pursuant to Entergy Corporation’s Relocation Assistance Policy and to certain additional relocation benefits, including the direct purchase of his home at an agreed upon price, which the Personnel Committee determined was necessary to facilitate Mr. Bakken's transition to Entergy Corporation and to mitigate the expenses associated with his relocation. Mr. Bakken’s sign-on bonus and certain of his relocation benefits are subject to forfeiture if Mr. Bakken terminates his service prior to the one year anniversary of his date of hire.
Mr. Bakken is expected to be eligible to participate in the annual and long-term incentive plans at the same level as the other Named Executive Officers who are members of the Office of the Chief Executive, except Mr. Denault. Mr. Bakken was not eligible to participate in the 2014-2016 performance period, but received pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods, in accordance with the terms of the program. Mr. Bakken also participates in the Cash Balance Plan and the Cash Balance Equalization Plan, retirement plans that are available to all eligible executive officers hired on or after July 1, 2014. For more information about the Cash Balance Plan and the Cash Balance Equalization Plan, see “2016 Pension Benefits.” Beginning in 2017, Mr. Bakken also is eligible to participate in the annual stock option and restricted stock programs.
Mr. Bakken also participates in the Nuclear Retention Plan, a retention plan for officers and other leaders with expertise in the nuclear industry. The Personnel Committee authorized this plan to attract and retain key management and employee talent in the nuclear power field, a field that requires unique technical and other expertise that is in great demand in the utility industry. The plan provides for bonuses to be paid annually over a three-year employment period with the bonus opportunity dependent on the participant’s management level and continued employment. Each annual payment is equal to an amount ranging from 15% to 30% of the employee’s base salary as of their date of enrollment in the plan. Mr. Bakken’s participation in the plan commenced in May 2016 and in accordance with the terms and conditions of the plan, in May 2017, 2018, and 2019, subject to his continued employment, Mr. Bakken will receive a cash bonus equal to 30% of his base salary as of May 1, 2016. This plan does not allow for accelerated or pro-rated payout upon termination of any kind. The three year coverage period and percentage of base salary payable under the plan are consistent with the terms of participation of other senior nuclear officers who participate in this plan.
The terms of Mr. Bakken’s employment were reviewed by the Personnel Committee, were determined based on competitive market data, and were designed to reflect the competition for chief nuclear officer talent in the marketplace and the Committee’s assessment of the critical role this position plays in transforming the nuclear fleet and to encourage retention of his leadership in light of his marketability as a chief nuclear officer.
Post-Termination Agreements and other Compensation Arrangements
The Personnel 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 competes 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 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 of Entergy Corporation. 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 for the two fiscalcalendar years immediately preceding the fiscalcalendar year in which the termination of employment occurs. Under no circumstances can this multiple
exceed 2.99 times the sum of (a) the executive officer’s 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 or her 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 officer’s termination occurs, or if higher, the annual incentive award actually received under the Annual Incentive Plan for the fiscalcalendar year immediately preceding the fiscalcalendar 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. Entergy Corporation’sThe executive officers, including the Named Executive Officers, will not receive any tax gross up payments on any severance benefits received under this plan. For more information regarding the System Executive Continuity Plan, see “2015“2016 Potential Payments Upon Termination ofor Change in Control - SystemControl-System Executive Continuity 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 that officer. Entergy Corporation has voluntarily adopted a policy that any employment or severance agreements providing severance benefits in excess of 2.99 times the sum of an officer’s annual base salary and annual incentive award (other than the value of the vesting or payment of an outstanding equity-based award or the pro rata vesting or payment of an outstanding long-term incentive award) must be approved by Entergy Corporationits shareholders.
Entergy Corporation currently has a retention agreement with Mr. Denault. In general, Mr. Denault’s retention agreement provides for certain payments and benefits in the event of his termination of employment by Entergy other than for cause, by Mr. Denault for good reason or on account of his death or disability. As a result ofSee “2016 Potential Payments Upon Termination or Change in Control - Mr. Denault’s Retention Agreement.” Because Mr. Denault reachinghas reached age 55, certain severance payment provisions in his retention agreement no longer apply. Mr. Denault will not receive tax gross up payments on any payments or benefits he may receive under his agreement. Mr. Denault’s retention agreement was entered into in 2006 when he was Entergy Corporation’s Chief Financial Officer and was designed to reflect the competition for chief financial officer talent in the marketplace at that time and the Personnel Committee’s assessment of the critical role this position played in executing Entergy Corporation’s long-term financial and other strategic objectives. Based on the market data provided by its former independent compensation consultant, the Committee believes the benefits and payment levels under Mr. Denault’s retention agreement are consistent with market practices.
For additional information regarding the System Executive Continuity Plan and Mr. Denault’s retention agreement described above, see “2015“2016 Potential Payments Upon Termination or Change in Control.”
Compensation Policies and Practices
Entergy Corporation strives to ensure that its compensation philosophy and practices are in line with the best practices of companies in the utilityits industry as well as other companies in the S&P 500. Some of these practices include the following:
Clawback Provisions
Entergy Corporation has adopted a clawback policy that covers all individuals subject to Section 16 of the Exchange Act, including all of the members of the Office of the Chief Executive. 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 determined to be 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, in each case, 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 theEntergy Corporation’s financial statements, Entergy Corporation will seek to recover any compensation received by its 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 and Share Retention Requirements
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 shareholders. Annually, the Personnel Committee monitors the executive officers’ compliance with these guidelines.
|
| |
| Role | Value of Common Stock to be Owned |
| Chief Executive Officer | 6 times base salary |
| Executive Vice Presidents | 3 times base salary |
| Senior Vice Presidents | 2 times base salary |
| Vice Presidents | 1 time base salary |
Further, to ensure compliance with the guidelines, until an executive officer satisfies the stock ownership guidelines, the officer must retain:
all net after-tax shares paid out under the Long-Term Performance Unit Program;
all net after-tax shares of the restricted stock received upon vesting; and
at least 75% of the after-tax net shares received upon the exercise of Entergy Corporation stock options, except for stock options granted before January 1, 2014, as to which the executive officer must retain at least 75% of the after-tax net shares until the earlier of achievement of the stock ownership guidelines or five years from the date of exercise.
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 its 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 this 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 its securities. Entergy Corporation securities. It prohibits these transactions 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 CorporationAn anti-hedging policy has also been adopted an anti-hedging policy that prohibits officers, directors and employees from entering into hedging or monetization transactions involving itsEntergy 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 common stock or transactions
involving “short-sales” of itsEntergy Corporation’s common stock. The Entergy Corporation Board adopted this policy to require officers, directors and employees to continue to own
Entergy Corporation stock with the full risks and rewards of ownership, thereby ensuring continued alignment of their objectives with those of Entergy Corporation’sits other shareholders.
Roles and ResponsibilitiesHow Compensation Decisions Are Made
Role of the 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 Entergy Corporation’s Named Executive Officers. The Committee works with Entergy Corporation’s executive management to ensure that itsthe compensation policies and practices are consistent with Entergy Corporation’sits values and support the successful recruitment, development and retention of executive talent so Entergy Corporation can achieve its business objectives and optimize its long-term financial returns. Each year, Entergy Corporation’s Senior Vice President, Human Resources and Chief Diversity Officer presents the proposed compensation model for the following year, including the compensation elements, mix of elements and measures for each element, and consults with Entergy Corporation’s Chief Executive Officer on recommended compensation for senior executives. The Committee evaluates executive pay each year to ensure that the compensation policies and practices are consistent with Entergy Corporation’s philosophy. The Personnel Committee is responsible for, among its other duties, the following actions related to the Named Executive Officers:
developing and implementing compensation policies and programs for hiring, evaluating, and setting compensation for the executive officers, including any employment agreement with an executive officer;
evaluating the performance of Entergy Corporation’s Chairman and Chief Executive Officer; and
reporting, at least annually, to the Board on succession planning, including succession planning for the Chief Executive Officer.
Role of the Chief Executive Officer
The Personnel Committee solicits recommendations from Entergy Corporation’s Chief Executive Officer with respect to compensation decisions for the Named Executive Officers who are members of Entergy Corporation’s Office of the Chief Executive. Entergy Corporation’s Chief Executive Officer provides the Personnel Committee with an assessment of the performance of each of these Named Executive Officers and recommends compensation levels to be awarded to each of them. 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. However, the 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. The Personnel Committee also relies on the recommendations of Entergy Corporation’s senior human resources executive managementSenior Vice President, Human Resources with respect to compensation decisions, policies, and practices.
TheEntergy Corporation’s Chief Executive Officer may attend meetings of the Personnel Committee only at the invitation of the chair of the Personnel Committee and cannot call a meeting of the Committee. Since he is not a member of the Committee, he has no vote on matters submitted to the Committee. During 2015,2016, Mr. Denault attended all6 meetings of the Personnel Committee meetings.Committee.
Role of the Compensation Consultant
Entergy Corporation’s Personnel Committee has the sole authority for the appointment, compensation, and oversight of its outside compensation consultant. In 2015, Entergy Corporation’s PersonnelThe Committee conducts an annual review of the compensation consultant, and in 2016, it retained 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 Entergy Corporation’sthe compensation programs. Also in 2016, the Corporate Governance Committee retained Pay Governance to review and perform a competitive analysis of non-employee director compensation.
During 2015,2016, Pay Governance assisted the Committee with its responsibilities related to Entergy Corporation’s compensation programs for its executives. The Committee directed Pay Governance to: (i) regularly attend meetings of the 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 he was invited in 2015.2016.
Compensation Consultant Independence
To maintain 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 or 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 2015, Pay Governance,2016, the Personnel Committee’s independent compensation consultant, Pay Governance, did not provide any services to Entergy Corporation other than its services to the Personnel Committee and the Corporate Governance Committee. Annually, the Committee reviews the relationship with its compensation consultant, including services provided, quality of those services, and fees associated with services in its evaluation of the executive compensation consultant’s independence. The Committee also assesses Pay Governance’s independence under NYSE rules and has concluded that no conflict of interests exists that would prevent Pay Governance from independently advising the Personnel Committee.
Tax and Accounting Considerations
Section 162(m) of the IRSInternal Revenue Code (“the Code”) limits the tax deductibility by a publicly held corporation of compensation in excess of $1 million paid to theEntergy Corporation’s Chief Executive Officer or any of its other Named Executive Officers who may be Section 162(m) covered employees, 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 its Named Executive Officers. Likewise, the Personnel Committee considers financial accounting consequences as it structures the compensation packages that are provided to theEntergy Corporation’s 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’s success, such as encouraging employee retention and rewarding achievement of key goals.
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
20152016 Summary Compensation Tables
The following table summarizes the total compensation paid or earned by each of the Named Executive Officers for the fiscal year ended December 31, 2016, and to the extent required by SEC executive compensation disclosure rules, the fiscal years ended December 31, 2015 2014, and 2013.2014. For information on the principal positions held by each of the Named Executive Officers, see Item 10, “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 “2015 Potential Payments upon Termination or Change in 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 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 (1) | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation (8) | | Total | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation (8) | | Total |
| Theodore H. | | 2015 | |
| $607,806 |
| |
| $— |
| |
| $1,080,101 |
| |
| $257,866 |
| |
| $655,409 |
| |
| $1,184,600 |
| |
| $87,282 |
| |
| $3,873,064 |
| |
| Bunting, Jr. | | | | | | | | | | | | | | | | | |
| Group President | | | | | | | | | | | | | | | |
|
| |
| Utility Operations | | | | | | | | | | | | | | | |
|
| |
| of Entergy Corp. | | | | | | | | | | | | | | | | | |
| A. Christopher | | | 2016 | |
| $426,990 |
| |
| $650,000 |
| |
| $3,292,700 |
| |
| $— |
| |
| $529,375 |
| |
| $27,900 |
| |
| $140,601 |
| |
| $5,067,566 |
|
| Bakken, III | | | | | | | | | | | | | | | | | |
| Chief Nuclear | | | | | | | | | | | | | | | | | |
| Officer of Entergy | | | | | | | | | | | | | | | | | |
| Corp. | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Marcus V. Brown | | | 2016 | |
| $563,208 |
| |
| $— |
| |
| $1,144,648 |
| |
| $333,000 |
| |
| $550,550 |
| |
| $934,600 |
| |
| $34,381 |
| |
| $3,560,387 |
|
| General Counsel of | | | | | | | | | | | | | | | | | |
| Entergy Corp. | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Leo P. Denault | | 2015 | |
| $1,153,385 |
| |
| $— |
| |
| $4,356,362 |
| |
| $1,004,080 |
| |
| $1,681,875 |
| |
| $4,802,400 |
| |
| $88,795 |
| |
| $13,086,897 |
| | 2016 | |
| $1,191,462 |
| |
| $— |
| |
| $4,632,276 |
| |
| $1,235,800 |
| |
| $2,154,600 |
| |
| $4,166,800 |
| |
| $97,786 |
| |
| $13,478,724 |
|
| Chairman of the | | 2014 | |
| $1,103,173 |
| |
| $— |
| |
| $3,564,463 |
| |
| $923,260 |
| |
| $2,597,400 |
| |
| $3,578,200 |
| |
| $57,538 |
| |
| $11,824,034 |
| | 2015 | |
| $1,153,385 |
| |
| $— |
| |
| $4,356,362 |
| |
| $1,004,080 |
| |
| $1,681,875 |
| |
| $4,802,400 |
| |
| $88,795 |
| |
| $13,086,897 |
|
| Board and CEO - | | 2013 | |
| $1,039,253 |
| |
| $— |
| |
| $3,780,189 |
| |
| $400,000 |
| |
| $1,770,720 |
| |
| $630,800 |
| |
| $44,690 |
| |
| $7,665,652 |
| | 2014 | |
| $1,103,173 |
| |
| $— |
| |
| $3,564,463 |
| |
| $923,260 |
| |
| $2,597,400 |
| |
| $3,578,200 |
| |
| $57,538 |
| |
| $11,824,034 |
|
| Entergy Corp. | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | 2015 | |
| $320,131 |
| |
| $— |
| |
| $219,994 |
| |
| $51,345 |
| |
| $190,000 |
| |
| $102,300 |
| |
| $43,987 |
| |
| $927,757 |
| | 2016 | |
| $320,067 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $168,000 |
| |
| $268,600 |
| |
| $34,243 |
| |
| $1,070,242 |
|
| CEO - Entergy | | 2014 | |
| $300,941 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $193,878 |
| |
| $281,100 |
| |
| $33,311 |
| |
| $1,095,938 |
| | 2015 | |
| $320,131 |
| |
| $— |
| |
| $219,994 |
| |
| $51,345 |
| |
| $190,000 |
| |
| $102,300 |
| |
| $43,987 |
| |
| $927,757 |
|
| Mississippi | | 2013 | |
| $294,090 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $48,000 |
| |
| $142,368 |
| |
| $— |
| |
| $28,058 |
| |
| $737,140 |
| | 2014 | |
| $300,941 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $193,878 |
| |
| $281,100 |
| |
| $33,311 |
| |
| $1,095,938 |
|
| | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
|
|
| Andrew S. Marsh | | 2015 | |
| $532,245 |
| |
| $— |
| |
| $2,600,401 |
| |
| $273,840 |
| |
| $508,308 |
| |
| $670,200 |
| |
| $39,131 |
| |
| $4,624,125 |
| | 2016 | |
| $553,284 |
| |
| $— |
| |
| $1,144,648 |
| |
| $333,000 |
| |
| $509,061 |
| |
| $593,700 |
| |
| $47,484 |
| |
| $3,181,177 |
|
| Executive Vice | | 2014 | |
| $512,721 |
| |
| $— |
| |
| $940,837 |
| |
| $304,850 |
| |
| $706,388 |
| |
| $750,900 |
| |
| $26,722 |
| |
| $3,242,418 |
| | 2015 | |
| $532,245 |
| |
| $— |
| |
| $2,600,401 |
| |
| $273,840 |
| |
| $508,308 |
| |
| $670,200 |
| |
| $39,131 |
| |
| $4,624,125 |
|
| President and CFO - | | 2013 | |
| $477,846 |
| |
| $— |
| |
| $921,927 |
| |
| $256,000 |
| |
| $476,000 |
| |
| $157,700 |
| |
| $213,663 |
| |
| $2,503,136 |
| | 2014 | |
| $512,721 |
| |
| $— |
| |
| $940,837 |
| |
| $304,850 |
| |
| $706,388 |
| |
| $750,900 |
| |
| $26,722 |
| |
| $3,242,418 |
|
| Entergy Corp., | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy Arkansas, | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy Louisiana, | |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| |
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
| Entergy Mississippi, | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Entergy New | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Orleans, Entergy | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
|
|
| Texas | | | | | | | | | | | | | | | |
|
| | | | | | | | | | | | | | | |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | 2015 | |
| $344,035 |
| |
| $— |
| |
| $279,406 |
| |
| $57,050 |
| |
| $315,000 |
| |
| $288,100 |
| |
| $25,970 |
| |
| $1,309,561 |
| | 2016 | |
| $353,690 |
| |
| $— |
| |
| $326,988 |
| |
| $71,040 |
| |
| $224,690 |
| |
| $600,000 |
| |
| $26,018 |
| |
| $1,602,426 |
|
| CEO - Entergy | | 2014 | |
| $335,997 |
| |
| $— |
| |
| $321,902 |
| |
| $69,680 |
| |
| $263,835 |
| |
| $546,000 |
| |
| $20,641 |
| |
| $1,558,055 |
| | 2015 | |
| $344,035 |
| |
| $— |
| |
| $279,406 |
| |
| $57,050 |
| |
| $315,000 |
| |
| $288,100 |
| |
| $25,970 |
| |
| $1,309,561 |
|
| Louisiana | | 2013 | |
| $321,860 |
| |
| $5,000 |
| |
| $325,813 |
| |
| $48,000 |
| |
| $238,223 |
| |
| $— |
| |
| $16,547 |
| |
| $955,443 |
| | 2014 | |
| $335,997 |
| |
| $— |
| |
| $321,902 |
| |
| $69,680 |
| |
| $263,835 |
| |
| $546,000 |
| |
| $20,641 |
| |
| $1,558,055 |
|
| | | | | | | | | | | | | | | | | | |
| Hugh T. McDonald | | 2015 | |
| $371,602 |
| |
| $— |
| |
| $206,509 |
| |
| $41,076 |
| |
| $360,000 |
| |
| $127,200 |
| |
| $65,749 |
| |
| $1,172,136 |
| |
| CEO - Entergy | | 2014 | |
| $350,104 |
| |
| $— |
| |
| $229,873 |
| |
| $47,905 |
| |
| $228,879 |
| |
| $400,800 |
| |
| $48,766 |
| |
| $1,306,327 |
| |
| Arkansas | | 2013 | |
| $342,791 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $48,000 |
| |
| $191,562 |
| |
| $— |
| |
| $48,326 |
| |
| $855,303 |
| |
| | | (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (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 Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compen-sation (8) | | Total | | Year | | Salary (2) | | Bonus (3) | | Stock Awards (4) | | Option Awards (5) | | Non-Equity Incentive Plan Compen-sation (6) | | Change in Pension Value and Non-qualified Deferred Compen-sation Earnings (7) | |
All
Other
Compens-ation
(8) | | Total |
| Hugh T. McDonald | | | 2016 | |
| $167,595 |
| |
| $— |
| |
| $— |
| |
| $— |
| |
| $79,826 |
| |
| $476,100 |
| |
| $32,184 |
| |
| $755,705 |
|
| Former CEO - | | | 2015 | |
| $371,602 |
| |
| $— |
| |
| $206,509 |
| |
| $41,076 |
| |
| $360,000 |
| |
| $127,200 |
| |
| $65,749 |
| |
| $1,172,136 |
|
| Entergy Arkansas | | | 2014 | |
| $350,104 |
| |
| $— |
| |
| $229,873 |
| |
| $47,905 |
| |
| $228,879 |
| |
| $400,800 |
| |
| $48,766 |
| |
| $1,306,327 |
|
| | | | | | | | | | | | | | | | | |
|
|
| Sallie T. Rainer | | 2015 | |
| $304,783 |
| |
| $— |
| |
| $211,004 |
| |
| $43,358 |
| |
| $190,000 |
| |
| $189,100 |
| |
| $41,565 |
| |
| $979,810 |
| | 2016 | |
| $316,003 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $153,348 |
| |
| $346,300 |
| |
| $53,797 |
| |
| $1,148,780 |
|
| CEO - Entergy | | 2014 | |
| $296,288 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $171,500 |
| |
| $504,000 |
| |
| $32,250 |
| |
| $1,290,746 |
| | 2015 | |
| $304,783 |
| |
| $— |
| |
| $211,004 |
| |
| $43,358 |
| |
| $190,000 |
| |
| $189,100 |
| |
| $41,565 |
| |
| $979,810 |
|
| Texas | | 2013 | |
| $286,692 |
| |
| $10,000 |
| |
| $214,624 |
| |
| $46,400 |
| |
| $140,184 |
| |
| $57,800 |
| |
| $22,779 |
| |
| $778,479 |
| | 2014 | |
| $296,288 |
| |
| $— |
| |
| $236,190 |
| |
| $50,518 |
| |
| $171,500 |
| |
| $504,000 |
| |
| $32,250 |
| |
| $1,290,746 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | 2015 | |
| $266,752 |
| |
| $— |
| |
| $211,004 |
| |
| $51,345 |
| |
| $173,000 |
| |
| $104,500 |
| |
| $33,416 |
| |
| $840,017 |
| | 2016 | |
| $276,998 |
| |
| $— |
| |
| $229,752 |
| |
| $49,580 |
| |
| $67,302 |
| |
| $177,600 |
| |
| $33,807 |
| |
| $835,039 |
|
| CEO - Entergy New | | 2014 | |
| $260,880 |
| |
| $— |
| |
| $220,398 |
| |
| $45,292 |
| |
| $167,864 |
| |
| $135,700 |
| |
| $31,402 |
| |
| $861,536 |
| | 2015 | |
| $266,752 |
| |
| $— |
| |
| $211,004 |
| |
| $51,345 |
| |
| $173,000 |
| |
| $104,500 |
| |
| $33,416 |
| |
| $840,017 |
|
| Orleans | | 2013 | |
| $255,786 |
| |
| $10,000 |
| |
| $201,704 |
| |
| $40,000 |
| |
| $112,446 |
| |
| $67,900 |
| |
| $24,078 |
| |
| $711,914 |
| | 2014 | |
| $260,880 |
| |
| $— |
| |
| $220,398 |
| |
| $45,292 |
| |
| $167,864 |
| |
| $135,700 |
| |
| $31,402 |
| |
| $861,536 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Richard C. Riley | | | 2016 | |
| $325,020 |
| |
| $— |
| |
| $226,224 |
| |
| $34,780 |
| |
| $167,500 |
| |
| $277,900 |
| |
| $102,112 |
| |
| $1,133,536 |
|
| CEO - Entergy | | | | | | | | | | | | | | | | | |
| Arkansas | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | | | |
| Roderick K. West | | 2015 | |
| $638,876 |
| |
| $— |
| |
| $1,071,111 |
| |
| $262,430 |
| |
| $607,677 |
| |
| $543,900 |
| |
| $71,790 |
| |
| $3,195,784 |
| | 2016 | |
| $654,514 |
| |
| $— |
| |
| $1,116,424 |
| |
| $303,400 |
| |
| $461,384 |
| |
| $601,000 |
| |
| $73,706 |
| |
| $3,210,428 |
|
| Executive Vice | | 2014 | |
| $623,854 |
| |
| $— |
| |
| $1,010,324 |
| |
| $313,560 |
| |
| $857,280 |
| |
| $782,400 |
| |
| $43,648 |
| |
| $3,631,066 |
| | 2015 | |
| $638,876 |
| |
| $— |
| |
| $1,071,111 |
| |
| $262,430 |
| |
| $607,677 |
| |
| $543,900 |
| |
| $71,790 |
| |
| $3,195,784 |
|
| President and Chief | | 2013 | |
| $606,381 |
| |
| $— |
| |
| $2,318,926 |
| |
| $320,000 |
| |
| $583,315 |
| |
| $147,800 |
| |
| $27,045 |
| |
| $4,003,467 |
| |
| Administrative | | | | | | | | | | | | | | | | | | | |
| Officer - Entergy | | | | | | | | | | | | | | | | | |
| Corp. | | | | | | | | | | | | | | | | | |
| President | | | 2014 | |
| $623,854 |
| |
| $— |
| |
| $1,010,324 |
| |
| $313,560 |
| |
| $857,280 |
| |
| $782,400 |
| |
| $43,648 |
| |
| $3,631,066 |
|
| |
| (1) | Effective April 6, 2016, Mr. BuntingBakken was named Executive Vice President and Chief Nuclear Officer. Mr. Brown was not a Named Executive Officer in 2014 and 2013.2015. Effective May 1, 2016, Mr. McDonald retired from Entergy Arkansas. Mr. Riley succeeded Mr. McDonald as Chief Executive Officer, Entergy Arkansas. |
| |
| (2) | The amounts in column (c) represent the actual base salary paid to the Named Executive Officer. The 20152016 changes in base salaries noted in the Compensation Discussion and Analysis were effective in April 2015. The Named Executive Officers are paid on a bi-weekly basis2016, except for additional adjustments in (a) Mr. Brown’s base salary which was effective in May 2016, (b) Mr. Fisackerly’s base salary which was effective in November 2016, and during 2015 there(c) Mr. Riley’s base salary which was an extra pay period at Entergy Arkansas and Entergy Mississippi.effective in May 2016. |
| |
| (3) | The amountsamount in column (d) in 20132016 for Mr. Fisackerly, Mr. May, Mr. McDonald, Ms. Rainer, and Mr. Rice representBakken represents a cash sign-on bonus paid to Mr. Bakken in recognitionconnection with his commencement of their work supportingemployment with Entergy Corporation which is subject to forfeiture if Mr. Bakken terminates his service prior to the move to MISO.one-year anniversary of his date of hire. See “Compensation Arrangements - Mr. Bakken’s Employment” in Compensation Discussion and Analysis. |
| |
| (4) | The amounts in column (e) represent the aggregate grant date fair value of restricted stock, and performance units, granted under the 2011 Equity Ownership Plan and restricted stock units granted under the 2015 Equity Ownership Plan,Plans, each calculated in accordance with FASB ASC Topic 718, without taking into account estimated forfeitures. The grant date fair value of the restricted stock and the restricted stock units is based on the closing price of Entergy Corporation common stock on the date of grant. The grant date fair value of performance units is based on the probable outcome of the applicable performance 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 interest 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 is attained, the maximum amounts that will be received with respect to the performance units granted in 20152016 are as follows: Mr. Bunting, $1,177,690;Bakken, $1,643,134; Mr. Brown, $1,157,184; Mr. Denault, $5,951,380;$5,884,704; Mr. Fisackerly, $260,710;$254,016; Mr. Marsh, $1,177,690;$1,157,184; Mr. May, $368,590; Mr. McDonald, $260,710;$381,024; Ms. Rainer, $260,710;$254,016; Mr. Rice, $260,710;$254,016; Mr. Riley, $254,016; and Mr. West, $1,177,690.$1,157,184. |
| |
| (5) | The amounts in column (f) represent the aggregate grant date fair value of stock options granted under the 2011 Equity Ownership PlanPlans calculated in accordance with FASB ASC Topic 718. For a discussion of the relevant assumptions used in valuing these awards, see Note 12 to the financial statements. |
| |
| (6) | The amounts in column (g) represent cash payments made under the Annual Incentive Plan. |
| |
| (7) | For all of the Named Executive Officers, the amounts in column (h) include the annual actuarial increase in the present value of the Named Executive Officers’ benefits under all pension plans established by Entergy Corporation using interest rate and mortality rate assumptions consistent with those used in Entergy Corporation’s financial statements and include amounts which the Named Executive Officers may not currently be entitled to receive because such amounts are not vested (see “2015“2016 Pension Benefits”). None of the increase is attributable to above-market or preferential earnings on non-qualified deferred compensation (see “2015“2016 Non-qualified Deferred Compensation”). |
Non-qualified Deferred Compensation”). For 2013, the aggregate change in the actuarial present value of Messrs. Fisackerly’s, May’s, and McDonald’s pension benefit was a decrease of $103,400, $80,100, and $116,500, respectively.
| |
| (8) | The amounts in column (i) for 20152016 include (a) matching contributions by Entergy Corporation under the Savings Plan to each of the Named Executive Officers; (b) dividends paid on restricted stock when vested; (c) life insurance premiums; (d) tax gross up payments on club dues;dues and relocation expenses; and (e) perquisites and other compensation. The amounts are listed in the following table: |
| | Named Executive Officer | Company Contribution – Savings Plan | Dividends Paid on Restricted Stock | Life Insurance Premium | Tax Gross Up Payments | 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. |
| $11,130 |
|
| $30,560 |
|
| $7,482 |
|
| $— |
|
| $38,110 |
|
| $87,282 |
| |
| A. Christopher Bakken, III | |
| $15,900 |
|
| $— |
|
| $8,168 |
|
| $5,950 |
|
| $110,583 |
|
| $140,601 |
|
| Marcus V. Brown | |
| $— |
|
| $24,907 |
|
| $7,482 |
|
| $— |
|
| $1,992 |
|
| $34,381 |
|
| Leo P. Denault |
| $11,130 |
|
| $54,849 |
|
| $7,482 |
|
| $— |
|
| $15,334 |
|
| $88,795 |
|
| $11,130 |
|
| $67,465 |
|
| $7,482 |
|
| $— |
|
| $11,709 |
|
| $97,786 |
|
| Haley R. Fisackerly |
| $11,130 |
|
| $11,593 |
|
| $1,965 |
|
| $3,377 |
|
| $15,922 |
|
| $43,987 |
|
| $11,130 |
|
| $9,365 |
|
| $2,062 |
|
| $3,943 |
|
| $7,743 |
|
| $34,243 |
|
| Andrew S. Marsh |
| $11,059 |
|
| $24,866 |
|
| $3,206 |
|
| $— |
|
| $— |
|
| $39,131 |
|
| $11,130 |
|
| $31,494 |
|
| $4,860 |
|
| $— |
|
| $— |
|
| $47,484 |
|
| Phillip R. May, Jr. |
| $11,130 |
|
| $12,127 |
|
| $2,713 |
|
| $— |
|
| $— |
|
| $25,970 |
|
| $11,130 |
|
| $10,225 |
|
| $2,793 |
|
| $— |
|
| $1,870 |
|
| $26,018 |
|
| Hugh T. McDonald |
| $11,130 |
|
| $11,937 |
|
| $7,136 |
|
| $7,756 |
|
| $27,790 |
|
| $65,749 |
|
| $7,039 |
|
| $8,867 |
|
| $1,550 |
|
| $4,975 |
|
| $9,753 |
|
| $32,184 |
|
| Sallie T. Rainer |
| $11,130 |
|
| $12,068 |
|
| $3,232 |
|
| $2,409 |
|
| $12,726 |
|
| $41,565 |
|
| $11,130 |
|
| $9,224 |
|
| $6,268 |
|
| $2,744 |
|
| $24,431 |
|
| $53,797 |
|
| Charles L. Rice, Jr. |
| $11,130 |
|
| $9,970 |
|
| $4,859 |
|
| $1,850 |
|
| $5,607 |
|
| $33,416 |
|
| $11,130 |
|
| $7,935 |
|
| $4,907 |
|
| $2,475 |
|
| $7,360 |
|
| $33,807 |
|
| Richard C. Riley | |
| $11,130 |
|
| $9,862 |
|
| $2,548 |
|
| $26,911 |
|
| $51,661 |
|
| $102,112 |
|
| Roderick K. West |
| $11,130 |
|
| $41,411 |
|
| $2,610 |
|
| $— |
|
| $16,639 |
|
| $71,790 |
|
| $11,130 |
|
| $37,370 |
|
| $2,610 |
|
| $— |
|
| $22,596 |
|
| $73,706 |
|
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. The following perquisites and other compensation were provided by Entergy Corporation in 2015.2016.
|
| | | | | | |
Named Executive Officer | Relocation | Housing Allowance | Personal Use of Corporate Aircraft | Club Dues | Executive Physical Exams | Event Tickets |
Theodore H. Bunting, Jr.A. Christopher Bakken, III | X | | | | X | |
| Marcus V. Brown | | | | | X | X |
| Leo P. Denault | | | X | | X | |
| Haley R. Fisackerly | | | | X | X | |
| Andrew S. Marsh | | | | | X | |
| Phillip R. May, Jr. | | | | | X | |
| Hugh T. McDonald | | | | X | X | |
| Sallie T. Rainer | X | X | | X | | |
| Charles L. Rice, Jr. | | | | X | X | |
| Richard C. Riley | | | | X | | |
| Roderick K. West | | | X | | X | X |
For security and business reasons, Entergy Corporation permits its 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’s Chief Executive Officer. The amounts included in column (i) for the personal use of corporate aircraft, reflect the incremental cost to Entergy Corporation for use of the corporate aircraft, determined on the basis of 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. The aggregate incremental aircraft usage cost associated with Mr. Bunting’s personal use of the corporate aircraft was $35,728 for fiscal year 2015. In addition, Entergy Corporation offers its executives comprehensive annual physical exams at Entergy Corporation’s expense. Tickets to cultural and sporting events are purchased for business purposes, and if not utilized for business purposes, the tickets are made available to
the employees, including the Named Executive Officers, for personal use.
Entergy Corporation also provides relocation benefits to a broad base of employees which include assistance with moving expenses, purchase and sale of home, and transportation of household goods. In connection with his employment, and in accordance with its relocation policies and pursuant to certain additional relocation benefits, Entergy Corporation paid $103,849 in relocation expenses for Mr. Bakken in 2016. The relocation assistance amounts reported above represent the amount paid to Entergy’s relocation service provider or Mr. Bakken, as applicable. Certain of Mr. Bakken’s relocation benefits are subject to forfeiture if Mr. Bakken terminates his service prior to the one year anniversary of his date of hire.
In 2016 the Named Executive Officers who are not members of Entergy Corporation’s Office of the Chief Executive were provided club dues, tax gross ups on club dues, where appropriate, housing allowances. Entergy Corporation reimburses its Subsidiaries’ chief executive officers for club dues to encourage entertainment with business colleagues, and to engage with local leadership in the communities in which they serve. Mr. Riley incurred $51,661 in dues, which included a one-time membership fee. Entergy Corporation discontinued housing allowances for the Named Executive Officers in 2016. None of the other perquisites referenced above exceeded $25,000 for any of the other Named Executive Officers.
2015
2016 Grants of Plan-Based Awards
The following table summarizes award grants during 20152016 to the Named Executive Officers.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | |
| (a) | | (b) | | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | Approval Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| A. Christopher | | 4/6/16 | | | $- | $423,500 | $847,000 | | | | | | | | | | | | |
| Bakken, III | | 5/1/16 | 1/28/16 | | | | | | 1,822 |
| 7,289 |
| 14,578 |
| | | | | | | | $616,066 |
| | | 5/1/16 | 1/28/16 | | | | | | 910 |
| 3,639 |
| 7,278 |
| | | | | | | | $360,334 |
| | | | | | | | | | | | | | 30,000(6) |
| | | | | | $2,316,300 |
| | | | | | | | | | | | | | | | | | | | |
| Marcus V. | | 1/28/16 | | | $- | $423,500 | $847,000 | | | | | | | | | | | | |
| Brown | | 1/28/16 | | | | | | | 2,050 |
| 8,200 |
| 16,400 |
| | | | | | | | $693,064 |
| | | 1/28/16 | | | | | | | | | | | 6,400 |
| | | | | | $451,584 |
| | | 1/28/16 | | | | | | | | | | | | | 45,000 |
| | $70.56 | | $333,000 |
| | | | | | | | | | | | | | | | | | | | |
| | | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under- lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards | | Grant Date | Approval Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under-lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) | |
| Theodore H. | | 1/29/15 | | — | $428,372 | $856,744 | | | | | | | | | | | |
| Bunting, Jr. | | 1/29/15 | | 1,638 |
| 6,550 |
| 13,100 |
| | | | | | $648,581 | |
| | | 1/29/15 | | | | 4,800 |
| | | | $431,520 | |
| | | 1/29/15 | | | | | | 22,600 |
| | $89.90 | | $257,866 | |
| | | | | | | | | | ($) | | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Leo P. | | 1/29/15 | | — | $1,462,500 | $2,925,000 | | | | | | | | | 1/28/16 | | $- | $1,620,000 | $3,240,000 | | | | | | | |
| Denault | | 1/29/15 | | | | | 8,275 |
| 33,100 |
| 66,200 |
| | | | | | | | $3,277,562 | | 1/28/16 | | | | | 10,425 |
| 41,700 |
| 83,400 |
| | | | | | | | $3,524,484 |
| | | 1/29/15 | | | | 12,000 |
| | | | $1,078,800 | | 1/28/16 | | | | 15,700 |
| | | | $1,107,792 |
| | | 1/29/15 | | | | | | 88,000 |
| | $89.90 | | $1,004,080 | | 1/28/16 | | | | | | 167,000 |
| | $70.56 | | $1,235,800 |
| | | | | | | | | | | | | | | |
| Haley R. | | 1/29/15 | | — | $124,174 | $248,348 | | | | | | | | | | | | 1/28/16 | | $- | $140,000 | $280,000 | | | | | | | | | | |
| Fisackerly | | 1/29/15 | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $143,579 | | 1/28/16 | | | | | 450 |
| 1,800 |
| 3,600 |
| | | | | | | | $152,136 |
| | | 1/29/15 | | | | | | | 850 |
| | | | | | $76,415 | | 1/28/16 | | | | | | | 1,100 |
| | | | | | $77,616 |
| | | 1/29/15 | | | | | | | | | 4,500 |
| | $89.90 | | $51,345 | | 1/28/16 | | | | | | | | | 6,700 |
| | $70.56 | | $49,580 |
| | | | | | | | | | | | | | | |
| Andrew S. | | 1/29/15 |
| — | $376,524 | $753,048 |
|
|
|
|
|
|
|
|
| | | | | 1/28/16 |
| | $- | $391,586 | $783,172 |
|
|
|
|
|
|
|
|
| | | |
| Marsh | | 1/29/15 |
|
|
| 1,638 |
| 6,550 |
| 13,100 |
|
|
|
| | | | $648,581 | | 1/28/16 |
| |
|
|
| 2,050 |
| 8,200 |
| 16,400 |
|
|
|
| | | | $693,064 |
| | | 1/29/15 | | | | 5,000 |
| | | | $449,500 | | 1/28/16 | | | | 6,400 |
| | | | $451,584 |
| | | 8/3/15 | | | | 21,100 (6) |
| | | | $1,502,320 | | 1/28/16 | | | | | | 45,000 |
| | $70.56 | | $333,000 |
| | | 1/29/15 | | | | | | 24,000 |
| | $89.90 | | $273,840 | | | | | | | |
| | | | | | | | | |
| Phillip R. | | 1/29/15 | | — | $207,750 | $415,500 | | | | | | | | | | | | 1/28/16 | | $- | $213,990 | $427,980 | | | | | | | | | | |
| May, Jr. | | 1/29/15 | | | | | 513 |
| 2,050 |
| 4,100 |
| | | | | | | | $202,991 | | 1/28/16 | | | | | 675 |
| 2,700 |
| 5,400 |
| | | | | | | | $228,204 |
| | | 1/29/15 | | | | 850 |
| | | | $76,415 | | 1/28/16 | | | | 1,400 |
| | | | $98,784 |
| | | 1/29/15 | | | | | | 5,000 |
| | $89.90 | | $57,050 | | 1/28/16 | | | | | | 9,600 |
| | $70.56 | | $71,040 |
| | | | | | | | | | | | | | | |
| Hugh T. | | | 1/28/16 | | $- | $180,061 | $360,122 | | | | | | | | | | |
| McDonald | | | | | | | | |
| | | | | | | | | |
| Sallie T. | | | 1/28/16 | | $- | $127,790 | $255,580 | | | | |
| | |
| | | | |
| Rainer | | | 1/28/16 | | | | | 450 |
| 1,800 |
| 3,600 |
| | | | | | | | $152,136 |
| | | | 1/28/16 | | | | | | | 1,100 |
| | | | | | $77,616 |
| | | | 1/28/16 | | | | | | 6,700 |
| | $70.56 | | $49,580 |
| | | | | | | | | |
| Charles L. | | | 1/28/16 | | $- | $112,170 | $224,340 | | | | | | | |
| Rice, Jr. | | | 1/28/16 | | | | | 450 |
| 1,800 |
| 3,600 |
| | | | | | | | $152,136 |
| | | | 1/28/16 | | | | | | | 1,100 |
| | | | | | $77,616 |
| | | | 1/28/16 | | | | | | | | | 6,700 |
| | $70.56 | | $49,580 |
| | | | | | | | | |
| Richard C. | | | 1/28/16 | | $- | $134,000 | $268,000 | | | | | | | | | | |
| Riley | | | 1/28/16 | | | | | 450 |
| 1,800 |
| 3,600 |
| | | | | | | | $152,136 |
| | | | 1/28/16 | | | | | | | 1,050 |
| | | | | | $74,088 |
| | | | 1/28/16 | | | | | | 4,700 |
| | $70.56 | | $34,780 |
|
| | | | | | | | | | | | | | | | | | | | | | | |
| | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | |
| (a) | | (b) | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under- lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Hugh T. | | 1/29/15 | | — | $180,060 | $360,120 | | | | | | | | | | | | |
| McDonald | | 1/29/15 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $143,579 |
| | | 1/29/15 | | | | | | | | | | 700 |
| | | | | | $62,930 |
| | | 1/29/15 | | | | | | | | | | | | 3,600 |
| | $89.90 | | $41,076 |
| | | | | | | | | | | | | | | | | | | |
| Sallie T. | | 1/29/15 | | — | $122,910 | $245,820 | | | | | | | | | | | | |
| Rainer | | 1/29/15 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $143,579 |
| | | 1/29/15 | | | | | | | | | | 750 |
| | | | | | $67,425 |
| | | 1/29/15 | | | | | | | | | | | | 3,800 |
| | $89.90 | | $43,358 |
| | | | | | | | | | | | | | | | | | | |
| Charles L. | | 1/29/15 | | — | $107,388 | $214,776 | | | | | | | | | | | | |
| Rice, Jr. | | 1/29/15 | | | | | | 363 |
| 1,450 |
| 2,900 |
| | | | | | | | $143,579 |
| | | 1/29/15 | | | | | | | | | | 750 |
| | | | | | $67,425 |
| | | 1/29/15 | | | | | | | | | | | | 4,500 |
| | $89.90 | | $51,345 |
| | | | | | | | | | | | | | | | | | | |
| Roderick K. | | 1/29/15 | | — | $450,131 | $900,262 | | | | | | | | | | | | |
| West | | 1/29/15 | | | | | | 1,638 |
| 6,550 |
| 13,100 |
| | | | | | | | $648,581 |
| | | 1/29/15 | | | | | | | | | | 4,700 |
| | | | | | $422,530 |
| | | 1/29/15 | | | | | | | | | | | | 23,000 |
| | $89.90 | | $262,430 |
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1) | | Estimated Future Payouts under Equity Incentive Plan Awards(2) | | | | | | | | |
| (a) | | (b) | | | (c) | (d) | (e) | | (f) | (g) | (h) | | (i) | | (j) | | (k) | | (l) |
| Name | | Grant Date | Approval Date | | Thresh-old | Target | Maximum | | Thresh-old | Target | Maximum | | All Other Stock Awards: Number of Shares of Stock or Units | | All Other Option Awards: Number of Securities Under- lying Options | | Exercise or Base Price of Option Awards | | Grant Date Fair Value of Stock and Option Awards |
| | | | | | ($) | ($) | ($) | | (#) | (#) | (#) | | (#) (3) | | (#) (4) | | ($/Sh) | | ($) (5) |
| Roderick K. | | 1/28/16 | | | $- | $461,384 | $922,768 | | | | | | | | | | | | |
| West | | 1/28/16 | | | | | | | 2,050 |
| 8,200 |
| 16,400 |
| | | | | | | | $693,064 |
| | | 1/28/16 | | | | | | | | | | | 6,000 |
| | | | | | $423,360 |
| | | 1/28/16 | | | | | | | | | | | | | 41,000 |
| | $70.56 | | $303,400 |
| |
| (1) | The amounts in columns (c), (d), and (e) represent minimum, target, and maximum payment levels under the Annual 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’s total shareholder return relative to the total shareholder returns of the companies included in the Philadelphia Utility Index. There is no payout under the program if Entergy Corporation’s total shareholder return falls within the lowest quartile of the peer companies in the Philadelphia Utility Index. 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, 2017.2018.) Accrued dividends on the shares earned will also be paid in Entergy Corporation common stock. In connection with Mr. Bakken’s employment, the Personnel Committee, on January 28, 2016, awarded Mr. Bakken pro-rated target award opportunities for the 2015-2017 and 2016-2018 performance periods. Pursuant to the terms of the Long-Term Performance Unit Program, the grants were made on May 1, 2016, the first day of his first full month of employment. |
| |
| (3) | Except as otherwise noted in footnote 6, the amounts in column (i) represent shares of restricted stock granted under the 20112015 Equity Ownership Plan. Shares of restricted stock vest one-third on each of the first through third anniversaries of the grant date, 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 20112015 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. |
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 August 2015,April 2016, Mr. MarshBakken was awarded 21,10030,000 restricted stock units under the 2015 Equity Ownership Plan. TheShares of the restricted stock units will vest one-third on August 3, 2020.April 6, 2019, April 6, 2022, and April 6, 2025. |
2015
2016 Outstanding Equity Awards at Fiscal Year-End
The following table summarizes, for each Named Executive Officer, unexercised options, restricted stock that has not vested, and equity incentive plan awards outstanding as of the end of 2015.2016.
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Theodore H. | | — |
| | 22,600(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| Bunting, Jr. | | 9,500 |
| | 19,000(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 26,666 |
| | 13,334(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 9,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 6,800 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 14,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 12,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 18,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 10,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 1,638(4) | | $111,974 |
| | | | | | | | | | | | | | | | | 9,400(5) | | $642,584 |
| | | | | | | | | | | | | 4,800(6) | | $328,128 | | | | |
| | | | | | | | | | | | | 3,000(7) | | $205,080 | | | | |
| | | | | | | | | | | | | 1,667(8) | | $113,956 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Leo P. | | — |
| | 88,000(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| Denault | | 35,333 |
| | 70,667(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 33,333 |
| | 16,667(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 25,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 45,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 60,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | 50,000 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | | |
| | | | | | | | | | | | | | | | | 8,275(4) | | $565,679 |
| | | | | | | | | | | | | | | | | 40,000(5) | | $2,734,400 |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| A. Christopher | | | | | | | | | | | | | | | | 7,289(4) | | $535,523 |
| Bakken, III | | | | | | | | | | | | | | | | 910(5) | | $66,858 |
| | | | | | | | | | | | | 30,000(9) | | $2,204,100 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Marcus V. | | — |
| | 45,000(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Brown | | 8,000 |
| | 16,000(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 20,333 |
| | 10,167(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 16,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 2,800 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 7,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 4,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 3,500 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | | | | | | | | | | | | | | | 8,200(4) | | $602,454 |
| | | | | | | | | | | | | | | | | 1,638(5) | | $120,344 |
| | | | | | | | | | | | | 6,400(6) | | $470,208 | | | | |
| | | | | | | | | | | | | 3,334(7) | | $244,949 | | | | |
| | | | | | | | | | | | | 1,634(8) | | $120,050 | | | | |
| | | | | Option Awards | | Stock Awards | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Leo P. | | | — |
| | 167,000(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Denault | | | 29,333 |
| | 58,667(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | | 70,666 |
| | 35,334(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | | 50,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | | 25,000 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | | 50,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | | 45,000 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | | 50,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | | 60,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | |
| | | | | | | | 41,700(4) | | $3,063,699 |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) | | |
| | |
| | | | | | | | | | | | 8,275(5) | | $607,964 |
| | | | | | | | | | | | | 12,000(6) | | $820,320 | | | | | | |
| | |
| | | | | | | | 15,700(6) | | $1,153,479 | | | | |
| | | | | | | | | | | | | 9,267(7) | | $633,492 | | | | | | | | | | | | | | | | 8,000(7) | | $587,760 | | | | |
| | | | | | | | | | | | | 2,000(8) |
| $136,720 | | | | | | | | | | | | | | | | 4,634(8) | | $340,460 | | | | |
| | | | | | | | | | | |
| Haley R. | | — |
| | 4,500(1) |
| | | | $89.90 |
| 1/29/2025 | | | | | | | | | | — |
| | 6,700(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Fisackerly | | — |
| | 3,867(2) |
| | | | $63.17 |
| 1/30/2024 | | | | | | | | | | 1,500 |
| | 3,000(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | — |
| | 2,000(3) |
| | | | $64.60 |
| 1/31/2023 | | | | | | | | | | — |
| | 1,934(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 1,534 |
| | — |
| | | | $71.30 |
| 1/26/2022 | | | | | | | | | | 2,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 |
| 1/27/2021 | | | | | | | | | | 1,534 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 9,000 |
| | — |
| | | | $77.10 |
| 1/28/2020 | | | | | | | | | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 3,800 |
| | — |
| | | | $77.53 |
| 1/29/2019 | | | | | | | | | | 9,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 5,000 |
| | — |
| | | | $108.20 |
| 1/24/2018 | | | | | | | 3,800 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | |
| | | 2,500 |
| | — |
| | $91.82 |
| 1/25/2017 | | | 5,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | |
| | | | | | | | | 363(4) | | $24,815 | | 2,500 |
| | — |
| | $91.82 | | 1/25/2017 | | 1,800(4) | | $132,246 |
| | | | | | | | | | | 2,200(5) | | $150,392 | | | | | | | | | | 363(5) | | $26,670 |
| | | | | | | | | | | | | 850(6) | | $58,106 | | | | | | | | | | | | | 1,100(6) | | $80,817 | |
| | | | | | | | | | | | | 934(7) | | $63,848 | | | | | | | | | | | | | | | | 567(7) | | $41,657 | | | | |
| | | | | | | 467(8) | | $31,924 | | | | | | | | | | 467(8) | | $34,310 | | | | |
| | | | | | | |
| Andrew S. | | — |
| | 24,000(1) |
| | $89.90 | | 1/29/2025 | | |
| Marsh | | 11,666 |
| | 23,334(2) |
| | $63.17 | | 1/30/2024 | | |
| | | 21,333 |
| | 10,667(3) |
| | $64.60 | | 1/31/2023 | | |
| | | 10,000 |
| | — |
| | $71.30 | | 1/26/2022 | | |
| | | 4,000 |
| | — |
| | $72.79 | | 1/27/2021 | | |
| | | 9,100 |
| | — |
| | $77.10 | | 1/28/2020 | | |
| | | 8,000 |
| | — |
| | $77.53 | | 1/29/2019 | | |
| | | 10,000 |
| | — |
| | $108.20 | | 1/24/2018 | | |
| | | 5,000 |
| | — |
| | $91.82 | | 1/25/2017 | | |
| | | 5,000 |
| | — |
| | $68.89 | | 1/26/2016 | | |
| | | | | | | 1,638(4) | | $111,974 | |
| | | | | | | 9,400(5) | | $642,584 | |
| | | | | | | 5,000(6) | | $341,800 | | |
| | | | | | | 3,267(7) | | $223,332 | | |
| | | | | | | 1,334(8) | | $91,192 | | |
| | | | | | | 21,100(9) | | $1,442,396 | | |
| | | | | | | |
| | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
| | | | | Option Awards | | Stock Awards | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Andrew S. | | | — |
| | 45,000(1) |
| | $70.56 | | 1/28/2026 | |
| Marsh | | | 8,000 |
| | 16,000(2) |
| | $89.90 | | 1/29/2025 | |
| | | | 23,333 |
| | 11,667(3) |
| | $63.17 | | 1/30/2024 | |
| | | | 32,000 |
| | — |
| | $64.60 | | 1/31/2023 | |
| | | | 10,000 |
| | — |
| | $71.30 | | 1/26/2022 | |
| | | | 4,000 |
| | — |
| | $72.79 | | 1/27/2021 | |
| | | | 9,100 |
| | — |
| | $77.10 | | 1/28/2020 | |
| | | | 8,000 |
| | — |
| | $77.53 | | 1/29/2019 | |
| | | | 10,000 |
| | — |
| | $108.20 | | 1/24/2018 | |
| | | | 5,000 |
| | — |
| | $91.82 | | 1/25/2017 | |
| | | | | | | | 8,200(4) | | $602,454 |
| | | | | | | | 1,638(5) | | $120,344 |
| | | | | | | | 6,400(6) | | $470,208 | |
| | | | | | | | 3,334(7) | | $244,949 | |
| | | | | | | | 1,634(8) | | $120,050 | |
| | | | | | | | 21,100(10) | | $1,550,217 | |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) | | | | | |
| Phillip R. | | — |
| | 5,000(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | | | — |
| | 9,600(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| May, Jr. | | 2,666 |
| | 5,334(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | | | 1,666 |
| | 3,334(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 4,000 |
| | 2,000(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | | | 5,333 |
| | 2,667(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | | | 6,000 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 6,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | 4,700 |
| | — |
| | $77.53 | | 1/29/2019 | | | 6,000 |
| | — |
| | | | $77.10 | | 1/28/2020 | |
| | | 6,500 |
| | — |
| | $108.20 | | 1/24/2018 | | | 4,700 |
| | — |
| | $77.53 | | 1/29/2019 | |
| | | 5,000 |
| | — |
| | $91.82 | | 1/25/2017 | | | 6,500 |
| | — |
| | $108.20 | | 1/24/2018 | |
| | | 4,500 |
| | — |
| | $68.89 | | 1/26/2016 | | | 5,000 |
| | — |
| | $91.82 | | 1/25/2017 | |
| | | | | | | | | | | | | | | | | 513(4) | | $35,069 | | | | | | | | | | | | | | | | 2,700(4) | | $198,369 |
| | | | | | | | | | | | | | | | | 3,100(5) | | $211,916 | | | | | | | | | | | | | | | | 513(5) | | $37,690 |
| | | | | | | | | | | | | 850(6) | | $58,106 | | | | | | | | | | | | | | | | 1,400(6) | | $102,858 | | | | |
| | | | | | | | | | | | | 1,200(7) | | $82,032 | | | | | | | | | | | | | | | | 567(7) | | $41,657 | | | | |
| | | | | | | 467(8) | | $31,924 | | | | | | | 600(8) | | $44,082 | |
| | | | | | | |
| Hugh T. | | — |
| | 3,600(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | | |
| McDonald | | 1,833 |
| | 3,667(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | | |
| | | 4,000 |
| | 2,000(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | | |
| | | 4,600 |
| | — |
| | | | $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 | | | | | | |
| | | | | | | | | | | | | | | | | 363(4) | | $24,815 | |
| | | | | | | | | | | | | | | | | 2,200(5) | | $150,392 | |
| | | | | | | | | | | | | 700(6) | | $47,852 | | | | | |
| | | | | | | | | | | | | 867(7) | | $59,268 | | | | | |
| | | | | | | 467(8) | | $31,924 | | | | | |
| | | | | | | |
| Sallie T. | | — |
| | 3,800(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | | |
| Rainer | | 1,933 |
| | 3,867(2) |
| | | | $63.17 | | 1/30/2024 | | |
| | | 3,866 |
| | 1,934(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | | |
| | | 1,200 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | | |
| | | | | Option Awards | | Stock Awards | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Hugh T. | | | 3,600 |
| | — |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| McDonald | | | 1,834 |
| | — |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | | 4,600 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | | |
| | | | 4,600 |
| | — |
| | | | $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 | |
| | | | | | | | | | | | | | | | | | 161(5) | | $11,829 |
| | | | | | | |
| Sallie T. | | | — |
| | 6,700(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Rainer | | | 1,266 |
| | 2,534(2) |
| | | | $89.90 | | 1/29/2025 | |
| | | | 3,866 |
| | 1,934(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | | 5,800 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) | | 2,500 |
| | — |
| | | | $77.10 | | 1/28/2020 | | | | | | | | |
| | | 2,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | | | 1,200 |
| | — |
| | | | $77.53 | | 1/29/2019 | | | | | | | | |
| | | 2,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | | | 2,300 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $68.89 | | 1/26/2016 | | | | | | | 2,000 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | |
| | | |
| | |
| | | | | | | | 363(4) | | $24,815 | | |
| | |
| | | | | | | | 1,800(4) | | $132,246 |
| | | | | | | | | | | | | 2,200(5) | | $150,392 | | | | | | | | | | | | 363(5) | | $26,670 |
| | | | | | | | | 750(6) | | $51,270 | | | | | | | | | | | | 1,100(6) | | $80,817 | | | | |
| | | | | | | | | | | | | 934(7) | | $63,848 | | | | | | | | | | | | | | | | 500(7) | | $36,735 | | | | |
| | | | | | | 467(8) | | $31,924 | | | | | | | | | | 467(8) | | $34,310 | | | | |
| | | | | | | | | | | |
| Charles L. | | — |
| | 4,500(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | | | — |
| | 6,700(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Rice, Jr. | | 1,733 |
| | 3,467(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | | | 1,500 |
| | 3,000(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 3,333 |
| | 1,667(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | | | — |
| | 1,734(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 4,600 |
| | — |
| | $71.30 | | 1/26/2022 | | | 4,600 |
| | — |
| | $71.30 | | 1/26/2022 | | | | | |
| | | 2,900 |
| | — |
| | | | $72.79 | | 1/27/2021 | | | | | | | 2,900 |
| | — |
| | $72.79 | | 1/27/2021 | |
| | | |
| | |
| | | | | | | | | | | | 363(4) | | $24,815 | | |
| | |
| | | | | | | | | | | | 1,800(4) | | $132,246 |
| | | |
| | |
| | | | | | | | | | | | 2,200(5) | | $150,392 | | |
| | |
| | | | | | | | | | | | 363(5) | | $26,670 |
| | | |
| | |
| | | | | | | | 750(6) | | $51,270 | | | | | | |
| | |
| | | | | | | | 1,100(6) | | $80,817 | | | | |
| | | |
| | |
| | | | | | | | 767(7) | | $52,432 | | | | | | |
| | |
| | | | | | | | 500(7) | | $36,735 | | | | |
| | | | | | | 400(8) | | $27,344 | | | | | | | | | | 384(8) | | $28,212 | | | | |
| | | | | | | |
| Roderick | | — |
| | 23,000(1) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | | |
| K. West | | 12,000 |
| | 24,000(2) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | | |
| | | 26,666 |
| | 13,334(3) |
| | | | $64.60 | | 1/31/2023 | | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | | |
| | | 7,000 |
| | — |
| | | | $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 | | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 1,638(4) | | $111,974 | |
| | | |
| | |
| | | | | | | | | | | | 9,400(5) | | $642,584 | |
| | | |
| | |
| | | | | | | | 4,700(6) | | $321,292 | | | | | |
| | | |
| | |
| | | | | | | | 4,000(7) | | $273,440 | | | | | |
| | | |
| | |
| | | | | | | | 1,667(8) | | $113,956 | | | | | |
| | | | | | | 21,000(10) | | $1,435,560 | | | | |
|
| | | | | | | | | | | | | | | | | | | | |
| | | Option Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (g) | | (h) | | (i) | | (j) |
| Name | | Number of Securities Underlying Unexercised Options Exercisable | | Number of Securities Underlying Unexercised Options Unexercisable | | Equity Incentive Plan Awards: Number of Securities Underlying Unexercised Unearned Options | | Option Exercise Price | | Option Expiration Date | | Number of Shares or Units of Stock That Have Not Vested | | Market Value of Shares or Units of Stock That Have Not Vested | | Equity Incentive Plan Awards: Number of Unearned Shares, Units or Other Rights That Have Not Vested | | Equity Incentive Plan Awards: Market or Payout Value of Unearned Shares, Units or Other Rights That Have Not Vested |
| | | (#) | | (#) | | (#) | | ($) | | | | (#) | | ($) | | (#) | | ($) |
| Richard C. | | — |
| | 4,700(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| Riley | | 1,500 |
| | 3,000(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | 2,667 |
| | 2,667(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 3,334 |
| | — |
| | | | $64.60 | | 1/31/2023 | | | | | | | | |
| | | 2,500 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 4,000 |
| | — |
| | | | $108.20 | | 1/24/2018 | | | | | | | | |
| | | 2,400 |
| | — |
| | | | $91.82 | | 1/25/2017 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 1,800(4) | | $132,246 |
| | | |
| | |
| | | | | | | | | | | | 363(5) | | $26,670 |
| | | |
| | |
| | | | | | | | 1,050(6) | | $77,144 | | | | |
| | | |
| | |
| | | | | | | | 734(7) | | $53,927 | | | | |
| | | |
| | |
| | | | | | | | 500(8) | | $36,735 | | | | |
| | | | | | | | | | | | | | | | | | | |
| Roderick | | — |
| | 41,000(1) |
| | | | $70.56 | | 1/28/2026 | | | | | | | | |
| K. West | | 7,666 |
| | 15,334(2) |
| | | | $89.90 | | 1/29/2025 | | | | | | | | |
| | | — |
| | 12,000(3) |
| | | | $63.17 | | 1/30/2024 | | | | | | | | |
| | | 30,000 |
| | — |
| | | | $71.30 | | 1/26/2022 | | | | | | | | |
| | | 7,000 |
| | — |
| | | | $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 | | | | | | | | |
| | | |
| | |
| | | | | | | | | | | | 8,200(4) | | $602,454 |
| | | |
| | |
| | | | | | | | | | | | 1,638(5) | | $120,344 |
| | | |
| | |
| | | | | | | | 6,000(6) | | $440,820 | | | | |
| | | |
| | |
| | | | | | | | 3,134(7) | | $230,255 | | | | |
| | | |
| | |
| | | | | | | | 2,000(8) | | $146,940 | | | | |
| | | |
| | |
| | | | | | | | 21,000(11) | | $1,542,870 | | | | |
| |
| (1) | Consists of options that vested or will vest as follows: 1/3 of the options granted vest on each of 1/29/2016,28/2017, 1/29/2017,28/2018, and 1/29/2018.28/2019. |
| |
| (2) | Consists of options that vested or will vest as follows: 1/2 of the remaining unexercisable options vest on each of 1/30/201629/2017 and 1/30/2017.29/2018. |
| |
| (3) | The remaining unexercisable options vested on 1/31/2016.30/2017. |
| |
| (4) | Consists of performance units that will vest on December 31, 20172018 based on Entergy Corporation’s total shareholder return performance over the 2015-20172016-2018 performance period, as described under “What Entergy Corporation Pays and Why- Executive Compensation Elements - Variable - Long-Term Incentive Compensation - Performance Unit Program” in Compensation Discussion and Analysis. |
| |
| (5) | Consists of performance units that will vest on December 31, 20162017 based on Entergy Corporation’s total shareholder return performance over the 2014-20162015-2017 performance 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 1/29/2016,28/2017, 1/29/2017,28/2018, and 1/29/2018.28/2019. |
| |
| (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 1/30/201629/2017 and 1/30/2017.2/2018. |
| |
| (8) | Consists of shares of restricted stock that vested on 1/31/2016.30/2017. |
| |
| (9) | Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest one third on April 6, 2019, April 6, 2022, and April 6, 2025. |
| |
| (10) | Consists of restricted stock units granted under the 2015 Equity Ownership Plan which will vest on August 3, 2020. |
| |
(10)(11) | Consists of restricted stock units granted under the 2011 Equity Ownership Plan which will vest on May 1, 2018. |
20152016 Option Exercises and Stock Vested
The following table provides information concerning each exercise of stock options and each vesting of stock during 20152016 for the Named Executive Officers.
| | | | | Options Awards | | Stock Awards | | Options Awards | | Stock Awards |
| (a) | | (b) | | (c) | | (d) | | (e) | | (b) | | (c) | | (d) | | (e) |
| Name | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting | | Number of Shares Acquired on Exercise | | Value Realized on Exercise | | Number of Shares Acquired on Vesting | | Value Realized on Vesting |
| | | (#) | | ($) | | (#) | | ($) | | (#) | | ($) | | (#) | | ($) |
| Theodore H. Bunting, Jr. | | — |
| |
| $— |
| | 6,044(1) | |
| $519,185 |
| |
| A. Christopher Bakken, III | | | — |
| |
| $— |
| | — |
| |
| $— |
|
| | | | | | | | | | |
| Marcus V. Brown | | | — |
| |
| $— |
| | 7,881(1) |
| |
| $588,641 |
|
| | | | | | | | | | | | | | | |
| Leo P. Denault | | — |
| |
| $— |
| | 18,611(1) | |
| $1,479,832 |
| | — |
| |
| $— |
| | 27,008(1) |
| |
| $2,001,835 |
|
| | | | | | | | | | | | | | | |
| Haley R. Fisackerly | | 3,933 |
| |
| $52,946 |
| | 1,877(1) | |
| $166,112 |
| | 1,933 |
| |
| $27,093 |
| | 2,117(1) |
| |
| $160,856 |
|
| | | | | | | | | | | | | | | |
| Andrew S. Marsh | | — |
| |
| $— |
| | 5,565(1) | |
| $471,926 |
| | — |
| |
| $— |
| | 8,481(1) |
| |
| $638,206 |
|
| | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | | — |
| |
| $— |
| | 2,316(1) | |
| $199,139 |
| | — |
| |
| $— |
| | 2,619(1) |
| |
| $197,819 |
|
| | | | | | | | | | | | | | | |
| Hugh T. McDonald | | — |
| |
| $— |
| | 1,878(1) | |
| $166,588 |
| | 9,666 |
| |
| $93,899 |
| | 1,811(1) |
| |
| $138,530 |
|
| | | | | | | | | | | | | | | |
| Sallie T. Rainer | | — |
| |
| $— |
| | 1,911(1) | |
| $169,607 |
| | — |
| |
| $— |
| | 2,084(1) |
| |
| $158,415 |
|
| | | | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | — |
| |
| $— |
| | 1,677(1) | |
| $146,877 |
| | 8,466 |
| |
| $89,545 |
| | 1,933(1) |
| |
| $146,290 |
|
| | | | | | | | | | | | | | | |
| Richard C. Riley | | | — |
| |
| $— |
| | 6,233(1)(2) |
| |
| $489,466 |
|
| | | | | | | | | | |
| Roderick K. West | | 17,000 |
| |
| $159,346 |
| | 7,178(1) | |
| $630,108 |
| | 64,000 |
| |
| $748,718 |
| | 9,081(1) |
| |
| $687,112 |
|
| |
| (1) | Represents the value of performance units for the 2013-20152014-2016 performance period (payable solely in shares based on the closing stock price of Entergy Corporation on the date of vesting) under the Performance Unit Program and the vesting of shares of restricted stock in 2015.2016. |
| |
| (2) | Includes the cash settlement on April 1, 2016 of 4,000 restricted stock units granted under the 2007 Equity Ownership Plan. |
20152016 Pension Benefits
The following table shows the present value as of December 31, 2015,2016, 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. Additional information regarding these retirement plans follows this table. 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 2015 | | Plan Name | | Number of Years Credited Service | | Present Value of Accumulated Benefit | | Payments During 2016 |
Theodore H. Bunting, Jr. (1) | | Non-qualified System Executive Retirement Plan | | 27.86 |
| |
| $4,940,000 |
| |
| $— |
| |
| A. Christopher Bakken, III | | | Cash Balance Equalization Plan | | 0.74 |
| |
| $11,700 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 27.86 |
| |
| $969,200 |
| |
| $— |
| | Cash Balance Plan | | 0.74 |
| |
| $16,200 |
| |
| $— |
|
| | | | | | | | | | | | | |
Leo P. Denault (2) | | Non-qualified System Executive Retirement Plan | | 31.83 |
| |
| $14,323,900 |
| |
| $— |
| |
| Marcus V. Brown | | | System Executive Retirement Plan | | 21.74 |
| |
| $3,744,800 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 21.74 |
| |
| $739,300 |
| |
| $— |
|
| | | | | | | | |
Leo P. Denault (1) | | | System Executive Retirement Plan | | 32.83 |
| |
| $18,400,200 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 16.83 |
| |
| $564,100 |
| |
| $— |
| | Entergy Retirement Plan | | 17.83 |
| |
| $654,600 |
| |
| $— |
|
| | | | | | | | | | | | | |
| Haley R. Fisackerly | | Non-qualified System Executive Retirement Plan | | 20.08 |
| |
| $944,500 |
| |
| $— |
| | System Executive Retirement Plan | | 21.08 |
| |
| $1,123,300 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 20.08 |
| |
| $539,800 |
| |
| $— |
| | Entergy Retirement Plan | | 21.08 |
| |
| $629,600 |
| |
| $— |
|
| | | | | | | | | | | | | |
| Andrew S. Marsh | | Non-qualified System Executive Retirement Plan | | 17.37 |
| |
| $2,297,400 |
| |
| $— |
| | System Executive Retirement Plan | | 18.37 |
| |
| $2,822,400 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 17.37 |
| |
| $349,100 |
| |
| $— |
| | Entergy Retirement Plan | | 18.37 |
| |
| $417,800 |
| |
| $— |
|
| | | | | | | | | | | | | |
| Phillip R. May, Jr. | | Non-qualified System Executive Retirement Plan | | 29.56 |
| |
| $1,638,600 |
| |
| $— |
| | System Executive Retirement Plan | | 30.56 |
| |
| $2,114,100 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 29.56 |
| |
| $884,200 |
| |
| $— |
| | Entergy Retirement Plan | | 30.56 |
| |
| $1,008,700 |
| |
| $— |
|
| | | | | | | | | | | | | |
Hugh T. McDonald (1) | | Non-qualified System Executive Retirement Plan | | 33.93 |
| |
| $1,734,000 |
| |
| $— |
| |
Hugh T. McDonald (2) | | | System Executive Retirement Plan | | 34.35 |
| |
| $— |
| |
| $2,985,597 |
|
| | | Qualified defined benefit plan | | 32.44 |
| |
| $1,150,500 |
| |
| $— |
| | Entergy Retirement Plan | | 32.86 |
| |
| $1,626,600 |
| |
| $57,414 |
|
| | | | | | | | | | | | | |
Sallie T. Rainer (1) | | Non-qualified System Executive Retirement Plan | | 31.38 |
| |
| $964,600 |
| |
| $— |
| |
Sallie T. Rainer (2) | | | System Executive Retirement Plan | | 32.38 |
| |
| $1,168,300 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 31.00 |
| |
| $1,024,400 |
| |
| $— |
| | Entergy Retirement Plan | | 32.00 |
| |
| $1,167,000 |
| |
| $— |
|
| | | | | | | | | | | | | |
| Charles L. Rice, Jr. | | Non-qualified System Executive Retirement Plan | | 6.47 |
| |
| $340,400 |
| |
| $— |
| | System Executive Retirement Plan | | 7.47 |
| |
| $468,100 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 6.47 |
| |
| $177,700 |
| |
| $— |
| | Entergy Retirement Plan | | 7.47 |
| |
| $227,600 |
| |
| $— |
|
| | | | | | | | | | | | | |
Richard C. Riley (3) | | | System Executive Retirement Plan | | 27.01 |
| |
| $1,415,700 |
| |
| $— |
|
| | | | Entergy Retirement Plan | | 21.55 |
| |
| $700,800 |
| |
| $— |
|
| | | | | | | | |
| Roderick K. West | | Non-qualified System Executive Retirement Plan | | 16.75 |
| |
| $3,374,600 |
| |
| $— |
| | System Executive Retirement Plan | | 17.75 |
| |
| $3,902,600 |
| |
| $— |
|
| | | Qualified defined benefit plan | | 16.75 |
| |
| $387,500 |
| |
| $— |
| | Entergy Retirement Plan | | 17.75 |
| |
| $460,500 |
| |
| $— |
|
| |
| (1) | In 2006, Mr. Denault entered into an agreement granting him an additional 15 years of service and permission to retire under the non-qualified System Executive Retirement Plan in the event his employment is terminated by his Entergy employer other than for cause (as defined in the retention agreement), by Mr. Denault for good reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional 15 years of service under the non-qualified System Executive Retirement Plan only if his Entergy employer grants him permission to retire. The additional 15 years of service increases the present value of his benefit by $3,627,700. |
| |
| (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. |
| |
(2)(3) | During 2006, Mr. Denault entered into an agreement granting him an additional 15 years ofRiley separated from Entergy and was subsequently rehired in June 1995. The Entergy Retirement Plan does not include any credit service and permissionprior to retire underhis rehire date, however, the non-qualified System Executive Retirement Plan in the event his employment is terminated by Entergy other than for cause (as defined in the retention agreement), by Mr. Denault for goodreflects a net credited service date of December 28, 1989. |
reason (as defined in the retention agreement), or on account of his death or disability. His retention agreement also provides that if he terminates employment for any other reason, he shall be entitled to the additional 15 years of service under the non-qualified System Executive Retirement Plan if his employer grants him permission to retire. The additional 15 years increases the present value of his benefit by $3,083,700.
Qualified Retirement Benefits
Defined Benefit PensionEntergy Retirement Plan
The qualified retirement plan in which the Named Executive Officers, except for Mr. Bakken, participate is a funded, tax-qualified, noncontributory final average pay defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of the Entergy System Companies. All Named Executive Officers are participants in this plan.companies. Benefits under the tax-qualified pensionthis plan are calculated as an annuity payable at age 65 and generally are equal to 1.5% of a participant’s Final Average Monthly Earnings (FAME) multiplied by years of service (not to exceed 40). “Earnings” for purposes of calculating FAME generally includes the employee’s base salary and eligible annual incentive award and excludes all other bonuses. FAME is calculated using the employee’s average monthly Earnings for the 60 consecutive months in which the employee’s earnings were highest during the 120 month period immediately preceding the employee’s retirement and includes up to 5 annual bonuses paid during the 60 month period. Benefits under the tax-qualifiedthis plan are payable monthly after attainment of at least age 55 and after separation from an Entergy System company, subject to a reduction for early commencement, as described below. The amount of annual earnings that may be considered in calculating FAME and benefits under the tax-qualified pension plan is limited by federal law.the Code. Participants are 100% vested in their benefit upon completing 5 years of vesting service or upon attainment of age 65 while an active participant in the plan. Contributions to the pension plan are made entirely by the Entergy System company employer and are paid into a trust fund from which the benefits of participants will beare paid.
Normal retirement age under the plan is age 65. Employees who terminate employment prior to age 55 and have a vested benefit in the plan may receive a reduced deferred vested retirement benefit commencing as early as age 55 that is based on the normal age 65 retirement benefit (reduced by 7% per year for the first 5 years commencement precedes age 65, and reduced by 6% for each additional year commencement precedes age 65). Employees who are at least age 55 with at least 10 years of vesting service upon termination of 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 age 65 retirement benefit reduced by 2% per year for each year that early retirement precedes age 65.
Mr. Denault, Mr. Bunting,Brown, and Mr. McDonaldMs. Rainer are eligible for subsidized early retirement benefits.
Cash Balance Plan
The qualified defined benefit pension plan in which employees whose most recent hire or rehire date is on or after July 1, 2014 participate is a funded, tax-qualified, noncontributory cash balance defined benefit pension plan that provides benefits to most of the non-bargaining unit employees of the Entergy System companies hired or rehired on or after July 1, 2014. Mr. Bakken is the only Named Executive Officer who participates in this plan. Generally, the normal retirement benefit under this plan, payable as a single life annuity commencing at normal retirement age 65, is determined by converting the balance of the participant’s nominal Cash Balance Account, which is equal to the sum of his or her annual pay credits and his or her annual interest credits, into an actuarially equivalent annuity, as those terms are defined under the plan. Pay credits are made on December 31 of each plan year and range from 4% to 8% of the participant’s eligible earnings, based upon the sum of his or her age and vesting service as of January 1 of the plan year. Interest credits are made on December 31 of each calendar year, beginning with the calendar year following the calendar year in which the participant first becomes a participant, and are calculated based upon the annual rate of interest on 30-year U. S. Treasury securities, as specified by the Internal Revenue Service, for the month of August preceding the first day of the applicable calendar year. The interest crediting rate applied for any plan year will never be less than 2.6%, and will never exceed 9%. A participant becomes vested in his or her Cash Balance plan benefit if he or she has at least 3 years of vesting service or attains age 65 while actively employed by an Entergy system company. Normal retirement age is 65, and if a participant terminates employment at that time, payment of his or her normal retirement benefit begins on the first day of the month following his or her normal retirement date. However, if a participant with a vested benefit terminates employment before
his or her normal retirement date, he or she can commence a terminated vested benefit as early as the first day of the month following his or her termination of employment. Participants may elect to receive various optional forms of actuarially equivalent benefit payments, if they satisfy the Plan’s eligibility requirements.
401(k) Savings Plan
The Savings Plan is a tax-qualified 401(k) retirement savings plan, wherein total combined before-tax and after-tax contributions may not exceed 30% of a participant’s base salary up to certain contribution limits defined by law.the Code. In addition, under the Savings Plan, the Entergy employer of Savings Plan participants, who participate in the final average pay defined benefit pension plan,Entergy Retirement Plan, matches an amount equal to seventy cents for each dollar contributed by participating employees, including the Named Executive Officers, other than Mr. Bakken, with respect to the first six percent6% of their eligible earnings under the plan for that pay period. The Entergy employer of Savings Plan participants who participate in the Cash Balance Plan makes a company matching contribution on behalf of the participant equal to one dollar for each dollar contributed by participating employees with respect to the first 6% of their eligible earnings each pay period. Participants who are age 50 or older as of the last day of the plan year and who have made the maximum before-tax deferral contributions for the plan year may make additional before-tax catch-up contributions to the savings plan up to $6,000 per year; however, catch-up contributions are not eligible for a company matching contribution.
Non-qualified Retirement Benefits
The Named Executive Officers are eligible to participate in certain non-qualified retirement benefit plans that provide retirement income, including the Pension Equalization Plan, the Cash Balance Equalization Plan, and the System Executive Retirement Plan. Each of these plans is an unfunded non-qualified defined benefit pension plan that provides benefits to key management employees. In these plans, as described below, an executive is typically enrolled in one or more non-qualified plans, but is 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 the earlier of recovery, separation from service due to disability, or retirement eligibility. Generally, spouses of participants who die before commencement of benefits may be eligible for a portion of the participant’s accrued benefit.
All of the Named Executive Officers, except Mr. Bakken, participate in both the Pension Equalization Plan and the System Executive Retirement Plan. Mr. Bakken participates in the Cash Balance Equalization Plan.
The Pension Equalization Plan
The Pension Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to eligible participants who also participate in the Entergy Retirement Plan from Entergy Corporation’sEntergy’s general assets of a single lump sum cash distribution generally 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.Entergy Retirement Plan. The Pension Equalization Plan also takes into account as eligible earnings certain incentive awards paid to certain participants under the Annual Incentive Plan not included in earnings under the Retirement Plan and includes supplemental credited service granted to a participant in calculating his or her benefit. 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 Entergy employer benefits. The Pension Equalization Plan benefit attributable to supplemental credited service is not vested until age 65. Subject to the prior written consent of the Entergy System company employer (which consent is deemed given if the participant’s employment is terminated within twenty-four24 months following a change in control by the employer without “Cause” or by the participant for “Good Reason,” each as defined in the plan), an employee with supplemental credited service 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 six6 months under Code Section 409A. Benefits payable prior to age 65 are subject to the same reductionsterminated vested or early retirement reduction factors as qualified plan benefits.benefits payable under the Entergy Retirement Plan.
Effective July 1, 2014, participants in the Pension Equalization Plan are no longer provided with supplemental credited service unless the grant of supplemental credited service was approved and accepted in writing by the plan administrator prior to July 1, 2014. In addition, the Pension Equalization Plan was amended effective July 1, 2014 to provide that employees who participate in the Entergy Corporation’s cash balance pension plan adopted June 30, 2014Cash Balance Plan are not eligible to participate in the Pension Equalization Plan and instead aremay be eligible to participate in a new Cash Balance Equalization Plan.
Cash Balance Equalization Plan
The Cash Balance Equalization Plan is a non-qualified unfunded restoration retirement plan that provides for the payment to eligible participants who participate in the Cash Balance Plan from Entergy Corporation’s general assets of a single lump sum cash distribution generally upon separation from service generally equal to the difference between the amount that would have been payable as a lump sum under the Cash Balance Plan, but for Code limitations on pension benefits and earnings that may be considered in calculating tax-qualified cash balance restoration plan.plan benefits, and the amount actually payable as a lump sum under the Cash Balance Plan. In the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the Cash Balance Plan, shall become fully vested in all benefits accrued under this plan as of the date of termination of employment and shall be entitled to a lump-sum payable under this plan generally as soon as reasonably practicable following the first day of the month after the termination of employment.
The System Executive Retirement Plan
The System Executive Retirement Plan is a non-qualified supplemental retirement plan that provides for a single sum payment at age 65. Like the Pension Equalization Plan, the System Executive Retirement Plan is designed to provide for the payment to eligible participants who participate in the Entergy Retirement Plan from Entergy Corporation's general assets of a single-sum cash distribution upon the participant’s 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 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 retirement plan benefit and typically any prior employer pension benefit available to the participant.Entergy Retirement Plan benefit.
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 | | Executives at Management Level 4 | | Executives at Management Level 1 - Mr. Denault | | Executives at Management Levels 2 and 3 - Messrs. Brown, Marsh, May, and West | | Executives at Management Level 4 - All Other Named Executive Officers |
| 20 Years | | 55.0% | | 50.0% | | 45.0% | | 55.0% | | 50.0% | | 45.0% |
| 30 years | | 65.0% | | 60.0% | | 55.0% | | 65.0% | | 60.0% | | 55.0% |
The System Executive Retirement Plan benefit is not vested until age 65. Subject to the prior written consent 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 six6 months under Code Section 409A. Benefits payable prior to age 65 are subject to the same reductionsterminated vested or early retirement reduction factors as qualified plan benefits.benefits payable under the Entergy Retirement Plan. Further, in the event of a change in control, participants whose employment is terminated without “Cause” or by the employee for “Good Reason,” as each is defined in the Planplan 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 six6 months under Code Section 409A. The System Executive Retirement Plan was closed to new executive officers effective July 1, 2014.
2015
2016 Non-qualified Deferred Compensation
The Executive Deferred Compensation Plan, the 2007 Equity Ownership Plan and Long-Term Cash Incentive Plan, and the 2011 Equity Ownership Plan allow for the deferral of compensation for the Named Executive Officers. As of December 31, 2015, none of the Named Executive Officers had deferred compensation balances under the equity ownership plans or the Executive Deferred Compensation Plan.
As of December 31, 2015,2016, Mr. May had a deferred account balance under a frozen Defined Contribution Restoration Plan. The amount is deemed invested, as chosen by the participant, in certain T. Rowe Price investment funds that are also available to the participant under the Savings Plan. Mr. May has elected to receive the deferred account balance after he retires. The Defined Contribution Restoration Plan, until it was frozen in 2005, credited eligible 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.
Defined Contribution Restoration Plan
| | | Name | | Executive Contributions in 2015 | | Registrant Contributions in 2015 | | Aggregate Earnings in 2015(1) | | Aggregate Withdrawals/ Distributions | | Aggregate Balance at December 31, 2015 | | Executive Contributions in 2016 | | Registrant Contributions in 2016 | | Aggregate Earnings in 2016(1) | | Aggregate Withdrawals/Distributions | | Aggregate Balance at December 31, 2016 |
| (a) | | (b) | | (c) | | (d) | | (e) | | (f) | | (b) | | (c) | | (d) | | (e) | | (f) |
| | | | | | | | | | | | | | | | | | | | | |
| Phillip R. May, Jr. | |
| $— |
| |
| $— |
| |
| ($147 | ) | |
| $— |
| |
| $1,574 |
| |
| $— |
| |
| $— |
| |
| $177 |
| |
| $— |
| |
| $1,751 |
|
| |
| (1) | Amounts in this column are not included in the Summary Compensation Table. |
20152016 Potential Payments uponUpon Termination or Change in Control
Entergy Corporation has plans and other arrangements that provide compensation to a Named Executive Officer if his or her employment terminates under specified conditions, including following a change in control of Entergy Corporation. In addition, in 2006 Entergy Corporation has entered into a retention agreement with Mr. Denault that provides for paymentspossibility of additional service credit under the System Executive Retirement Plan upon certain employment termination events.terminations of employment. There are no plans or agreements that would provide for payments to any of the Named Executive Officers solely upon a change in control.
The tables below reflect the amount of compensation each of the Named Executive Officers would have received if his or her employment with antheir Entergy System companyemployer had been terminated under various scenarios as of December 31, 2015.2016. For purposes of these tables, Entergy Corporation assumed that itsa stock price of $73.47 was $68.36,used, which was the closing market price on that date.December 30, 2016, the last trading day of the year.
|
| | | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Theodore H. Bunting, Jr. (1)(3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $3,110,593 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
|
| $428,412 |
|
| $428,412 |
|
| $428,412 |
| — |
|
| $386,234 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $149,230 |
|
| $149,230 |
|
| $149,230 |
| — |
|
| $386,234 |
|
Unvested Stock Options(8) | — |
| — |
| — |
|
| $148,743 |
|
| $148,743 |
|
| $148,743 |
| — |
|
| $148,743 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $329,017 |
|
| $329,017 |
| — |
|
| $700,133 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Leo P. Denault (1)(2) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $7,696,260 |
|
Performance Units:(6)(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
|
| $1,808,122 |
|
| $1,822,956 |
|
| $1,808,122 |
|
| $1,808,122 |
| — |
|
| $1,808,122 |
|
| 2015-2017 Performance Unit Program | — |
| — |
|
| $1,808,122 |
|
| $754,216 |
|
| $1,808,122 |
|
| $1,808,122 |
| — |
|
| $1,808,122 |
|
Unvested Stock Options(8) | — |
| — |
| — |
|
| $429,427 |
|
| $429,427 |
|
| $429,427 |
| — |
|
| $429,427 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $726,735 |
|
| $726,735 |
| — |
|
| $1,711,744 |
|
Welfare Benefits(10) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Haley Fisackerly (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $434,607 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $100,284 |
|
| $100,284 |
| — |
|
| $92,286 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $33,018 |
|
| $33,018 |
| — |
|
| $92,286 |
|
Unvested Stock Options(8) | — |
| — |
| — |
| — |
|
| $27,588 |
|
| $27,588 |
| — |
|
| $27,588 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $84,493 |
|
| $84,493 |
| — |
|
| $167,702 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $19,234 |
|
| | | | | | | | | |
|
| | | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (1)(2) | Disability | Death | Change in Control | Termination Related to a Change in Control |
A. Christopher Bakken, III(3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $1,808,950 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $178,238 |
|
| $178,238 |
| — |
|
| $477,555 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $178,508 |
|
| $178,508 |
| — |
|
| $558,372 |
|
| Unvested Stock Options | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| Unvested Restricted Stock | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $21,060 |
|
Unvested Restricted Stock Units(14) | — |
| — |
|
| $734,700 |
| — |
|
| $734,700 |
|
| $734,700 |
| — |
|
| $2,204,100 |
|
| | | | | | | | | |
Marcus V. Brown(1)(4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $3,085,500 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $320,843 |
|
| $320,843 |
|
| $320,843 |
| — |
|
| $477,555 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
|
| $200,794 |
|
| $200,794 |
|
| $200,794 |
| — |
|
| $558,372 |
|
Unvested Stock Options(9) | — |
| — |
| — |
|
| $235,667 |
|
| $235,667 |
|
| $235,667 |
| — |
|
| $235,667 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $743,296 |
|
| $743,296 |
| — |
|
| $898,979 |
|
Welfare Benefits(12) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Leo P. Denault (1)(5) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $8,010,000 |
|
Performance Units:(7)(8) | | |
| $2,384,102 |
| | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $1,621,262 |
|
| $1,621,262 |
|
| $1,621,262 |
| — |
|
| $2,384,102 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
|
| $1,021,233 |
|
| $1,021,233 |
|
| $1,021,233 |
| — |
|
| $2,791,860 |
|
Unvested Stock Options(9) | — |
| — |
|
| $849,903 |
|
| $849,903 |
|
| $849,903 |
|
| $849,903 |
| — |
|
| $849,903 |
|
Unvested Restricted Stock(11) | — |
| — |
|
| $2,243,774 |
| — |
|
| $2,243,774 |
|
| $2,243,774 |
| — |
|
| $2,243,774 |
|
Welfare Benefits(12) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Haley Fisackerly (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $490,000 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $71,045 |
|
| $100,284 |
| — |
|
| $124,899 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $44,082 |
|
| $33,018 |
| — |
|
| $139,593 |
|
Unvested Stock Options(9) | — |
| — |
| — |
| — |
|
| $39,410 |
|
| $27,588 |
| — |
|
| $39,410 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $141,870 |
|
| $84,493 |
| — |
|
| $169,641 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $18,846 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Andrew S. Marsh (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $2,734,105 |
|
Performance Units:(7) | |
| |
| |
| |
| | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $428,412 |
|
| $428,412 |
| — |
|
| $386,234 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $149,230 |
|
| $149,230 |
| — |
|
| $386,234 |
|
Unvested Stock Options(8) | — |
| — |
| — |
| — |
|
| $161,207 |
|
| $161,207 |
| — |
|
| $161,207 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $318,353 |
|
| $318,353 |
| — |
|
| $708,200 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,851 |
|
Unvested Stock Units(12) | — |
| — |
| — |
| — |
| 1,442,396 |
| 1,442,396 |
| — |
|
| $1,442,396 |
|
| | | | | | | | | |
Phillip R. May, Jr. (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $1,108,000 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $141,300 |
|
| $141,300 |
| — |
|
| $167,482 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $46,690 |
|
| $46,690 |
| — |
|
| $167,482 |
|
Unvested Stock Options(8) | — |
| — |
| — |
| — |
|
| $35,200 |
|
| $35,200 |
| — |
|
| $35,200 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $93,585 |
|
| $93,585 |
| — |
|
| $187,628 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,851 |
|
| | | | | | | | | |
Hugh T. McDonald (1)(3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $540,181 |
|
Performance Units:(7) | | | | |
| | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
|
| $100,284 |
|
| $100,284 |
|
| $100,284 |
| — |
|
| $92,286 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $33,018 |
|
| $33,018 |
|
| $33,018 |
| — |
|
| $92,286 |
|
Unvested Stock Options(8) | — |
| — |
| — |
|
| $26,550 |
|
| $26,550 |
|
| $26,550 |
| — |
|
| $26,550 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $78,819 |
|
| $78,819 |
| — |
|
| $151,935 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Sallie T. Rainer (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $430,185 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $100,284 |
|
| $100,284 |
| — |
|
| $92,286 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $33,018 |
|
| $33,018 |
| — |
|
| $92,286 |
|
Unvested Stock Options(8) | — |
| — |
| — |
| — |
|
| $27,337 |
|
| $27,337 |
| — |
|
| $27,337 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $82,305 |
|
| $82,305 |
| — |
|
| $160,537 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $19,234 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (1)(2) | Disability | Death | Change in Control | Termination Related to a Change in Control |
Andrew S. Marsh (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $2,852,981 |
|
Performance Units:(8) | |
| |
| |
| |
| | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $320,843 |
|
| $320,843 |
| — |
|
| $477,555 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $200,794 |
|
| $200,794 |
| — |
|
| $558,372 |
|
Unvested Stock Options(9) | — |
| — |
| — |
| — |
|
| $251,117 |
|
| $251,117 |
| — |
|
| $251,117 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $743,296 |
|
| $743,296 |
| — |
|
| $898,979 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,269 |
|
Unvested Stock Units(15) | — |
| — |
| — |
| — |
|
| $1,550,217 |
|
| $1,550,217 |
| — |
|
| $1,550,217 |
|
| | | | | | | | | |
Phillip R. May, Jr. (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $1,141,280 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $100,433 |
|
| $100,433 |
| — |
|
| $198,369 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $66,123 |
|
| $66,123 |
| — |
|
| $220,410 |
|
Unvested Stock Options(9) | — |
| — |
| — |
| — |
|
| $55,403 |
|
| $55,403 |
| — |
|
| $55,403 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $175,226 |
|
| $175,226 |
| — |
|
| $203,952 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,269 |
|
| | | | | | | | | |
Hugh T. McDonald (2) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Performance Units:(8) | | | | |
| | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $31,543 |
| — |
| — |
| — |
| — |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Unvested Stock Options(10) | — |
| — |
| — |
|
| $18,883 |
| — |
| — |
| — |
| — |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
Welfare Benefits(12) | — |
| — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| | | | | | | | | |
Sallie T. Rainer (1)(4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
|
| $71,045 |
|
| $71,045 |
|
| $71,045 |
| — |
|
| $124,899 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
|
| $44,082 |
|
| $44,082 |
|
| $44,082 |
| — |
|
| $92,286 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
|
| $39,410 |
|
| $39,410 |
|
| $39,410 |
| — |
|
| $92,286 |
|
Unvested Stock Options(9) | — |
| — |
| — |
| — |
|
| $139,446 |
|
| $139,446 |
| — |
|
| $27,337 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $160,537 |
|
Welfare Benefits(12) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $19,234 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement | Disability | Death | Change in Control | Termination Related to a Change in Control |
Charles R. Rice, Jr (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $375,858 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $100,284 |
|
| $100,284 |
| — |
|
| $92,286 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $33,018 |
|
| $33,018 |
| — |
|
| $92,286 |
|
Unvested Stock Options(8) | — |
| — |
| — |
| — |
|
| $24,259 |
|
| $24,259 |
| — |
|
| $24,259 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $71,641 |
|
| $71,641 |
| — |
|
| $142,743 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $19,234 |
|
| | | | | | | | | |
Roderick K. West (4) | | | | | | | | |
| | | | | | | | | |
Severance Payment(5) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $3,268,593 |
|
Performance Units:(7) | | | | | | | | |
| 2014-2016 Performance Unit Program | — |
| — |
| — |
| — |
|
| $428,412 |
|
| $428,412 |
| — |
|
| $386,234 |
|
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $149,230 |
|
| $149,230 |
| — |
|
| $386,234 |
|
Unvested Stock Options(8) | | | | |
| $174,693 |
|
| $174,693 |
| — |
|
| $174,693 |
|
Unvested Restricted Stock(9) | — |
| — |
| — |
| — |
|
| $361,078 |
|
| $361,078 |
| — |
|
| $767,877 |
|
Welfare Benefits(11) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,851 |
|
Unvested Restricted Units(13) | — |
| — |
|
| $1,435,560 |
| — |
| — |
| — |
| — |
|
| $1,435,560 |
|
|
| | | | | | | | | | | | | | | | | | | | |
| Benefits and Payments Upon Termination | Voluntary Resignation | For Cause | Termination for Good Reason or Not for Cause | Retirement (1)(2) | Disability | Death | Change in Control | Termination Related to a Change in Control |
Charles R. Rice, Jr (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $392,593 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $71,045 |
|
| $71,045 |
| — |
|
| $124,899 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $44,082 |
|
| $44,082 |
| — |
|
| $139,593 |
|
Unvested Stock Options(9) | — |
| — |
| — |
| — |
|
| $37,350 |
|
| $37,350 |
| — |
|
| $37,350 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $132,980 |
|
| $132,980 |
| — |
|
| $157,226 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $18,846 |
|
| | | | | | | | | |
Richard C. Riley (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $469,000 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $71,045 |
|
| $71,045 |
| — |
|
| $124,899 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $44,082 |
|
| $44,082 |
| — |
|
| $139,593 |
|
Unvested Stock Options(9) | | | | |
| $41,144 |
|
| $41,144 |
| — |
|
| $41,144 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $146,866 |
|
| $146,866 |
| — |
|
| $182,058 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $18,846 |
|
| | | | | | | | | |
Roderick K. West (3) | | | | | | | | |
| | | | | | | | | |
Severance Payment(6) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $3,361,512 |
|
Performance Units:(8) | | | | | | | | |
| 2015-2017 Performance Unit Program | — |
| — |
| — |
| — |
|
| $320,843 |
|
| $320,843 |
| — |
|
| $477,555 |
|
| 2016-2018 Performance Unit Program | — |
| — |
| — |
| — |
|
| $200,794 |
|
| $200,794 |
| — |
|
| $558,372 |
|
Unvested Stock Options(9) | | | | |
| $242,910 |
|
| $242,910 |
| — |
|
| $242,910 |
|
Unvested Restricted Stock(11) | — |
| — |
| — |
| — |
|
| $733,524 |
|
| $733,524 |
| — |
|
| $883,036 |
|
Welfare Benefits(13) | — |
| — |
| — |
| — |
| — |
| — |
| — |
|
| $28,269 |
|
Unvested Restricted Units(16) | — |
| — |
|
| $1,542,870 |
| — |
| — |
| — |
| — |
|
| $1,542,870 |
|
| |
| (1) | As of December 31, 2015, Mr. Bunting,2016, Mr. Denault, Mr. Brown, and Mr. McDonaldMs. Rainer are retirement eligible and would retire rather than voluntarily resign. |
| |
| (2) | Mr. McDonald retired effective April 30, 2016. |
Pension BenefitsBenefits:
| |
(2)(3) | In addition to the payments and benefits in the table, if a Named Executive Officer’s, other than Mr. Denault’s, Mr. Brown’s, and Ms. Rainer’s, employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his vested pension benefits upon attainment of age 55 and would have been eligible for early retirement benefits under the System Executive Retirement Plan calculated using early retirement reduction factors. For a description of the pension benefits, see “2016 Pension Benefits.” If a Named Executive Officer’s, other than Mr. Denault’s, Mr. Brown’s, and Ms. Rainer’s, employment were |
terminated for cause or each were to resign before age 65 without the permission of their Entergy employer, each would not receive a benefit under the System Executive Retirement Plan. In addition to the payments and benefits in the table, if Mr. Bakken’s employment were terminated under certain conditions relating to a change in control, on the first day of the month following the Qualifying Event (as defined in the Cash Balance Equalization Plan), he would have become vested in and have been entitled to receive his vested pension benefits accumulated in the Cash Balance Equalization Plan as of the date of the Qualifying Event so long as a forfeiture event does not occur as described in the plan. For a description of the pension benefits under the Cash Balance Equalization Plan, see “2016 Pension Benefits.”
| |
| (4) | In addition to the payments and benefits in the table, Mr. Brown and Ms. Rainer each would have been eligible to retire and entitled to receive vested pension benefits. For a description of the pension benefits available, see “2016 Pension Benefits.” In the event of a termination by their Entergy employer without cause or by the executive for good reason in connection with a change in control, Mr. Brown and Ms. Rainer each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if they do not have their Entergy employer’s permission to separate from employment. If Mr. Brown’s or Ms. Rainer’s employment were terminated for cause or if either were to retire before age 65 without the permission of their Entergy employer, they would not receive a benefit under the System Executive Retirement Plan. |
| |
| (5) | 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 was terminated by his Entergy Corporationemployer other than for cause, by Mr. Denault for good reason or on account of his death or disability, he would also be eligible for certain additional retirement benefits. For a description of these benefits, see “2016 Pension Benefits.” Otherwise, if Mr. Denault’s employment was terminated for cause or he was to retire from Entergy Corporation before age 65 without the permission of his Entergy System employer, he would not receive a benefit under the System Executive Retirement Plan. For a description of these benefits, see “2015 Pension Benefits.” |
| |
(3) | In addition to the payments and benefits in the table, Mr. Bunting and Mr. McDonald each would have been eligible to retire and entitled to receive his vested pension benefits. For a description of the pension benefits available, see “2015 Pension Benefits.” In the event of a termination by Entergy Corporation without cause or by the executive for good reason in connection with a change in control, Mr. Bunting and Mr. McDonald each would be eligible for subsidized early retirement benefits under the System Executive Retirement Plan even if he does not have permission from his Entergy System employer to separate from employment. If Mr. Bunting’s and Mr. McDonald’s employment were terminated for cause or they were to retire from Entergy Corporation before age 65 without the permission of their Entergy System employer, they would not receive a benefit under the System Executive Retirement Plan. |
| |
(4) | In addition to the payments and benefits in the table, if a Named Executive Officer’s, other than Messrs. Denault, Bunting, and McDonald, employment were terminated under certain conditions relating to a change in control, each also would have been entitled to receive his or her vested pension benefits upon attainment of age 55 and would have been eligible for early retirement benefits under the System Executive Retirement Plan |
calculated using early retirement reduction factors. For a description of the pension benefits, see “2015 Pension Benefits.” If a Named Executive Officer’s, other than Messrs. Denault, Bunting, and McDonald, employment were terminated for cause or each were to resign from Entergy Corporation before age 65 without the permission of his or her Entergy System employer, each would not receive a benefit under the System Executive Retirement Plan.
Severance Payments
| |
(5)(6) | In the event of a termination (not due to death or disability) by the executive for good reason or by the applicable Entergy Corporationemployer not for cause during the period beginning upon the occurrence of a “potential change in control” (as defined in the System Executive Continuity Plan) and ending on the 2nd anniversary of a change in control, each Named Executive Officer would be entitled to receive pursuant to the System Executive Continuity Plan a lump sum severance payment equal to a multiple of the sum of (1) their 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 (2) their annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for Messrs. Denault, Bunting, Marsh,2014 and West 2.99 times2015 (the two calendar years immediately preceding the calendar year in which termination occurs), but in no event shall the severance be more than the product of for Mr. May 22.99 times the product of, and Messrs. Fisackerly, McDonald, Rice, and Ms. Rainer the product of 1 time the sum of (a) his or hertheir 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) histhe higher of their actual annual incentive payment under the Annual Incentive Plan for the 2015 performance year or hertheir annual incentive, calculated using the average annual target opportunity derived under the Annual Incentive Plan for 20132014 and 20142015 (the two calendar years immediately preceding the calendar year in which his or her termination occurs). For purposes of this table, we assumeit assumed the following target opportunity and base salary:salary was assumed: |
| | | Named Executive Officer | Target Opportunity | Base Salary | Target Opportunity | Base Salary |
| Theodore H. Bunting, Jr. | 70% | $611,960 | |
| A. Christopher Bakken III | | 0% | $605,000 |
| Marcus V. Brown | | 70% | $605,000 |
| Leo P. Denault | 120% | $1,170,000 | 123% | $1,200,000 |
| Andrew S. Marsh | | 70% | $559,408 |
| Haley R. Fisackerly | 40% | $310,434 | 40% | $350,000 |
| Andrew S. Marsh | 70% | $537,892 | |
| Phillip R. May | 60% | $346,250 | |
| Hugh T. McDonald | 50% | $360,121 | |
| Phillip R. May Jr, | | 60% | $356,650 |
| Sallie T. Rainer | 40% | $307,275 | 40% | $319,475 |
| Charles L. Rice, Jr. | 40% | $268,470 | 40% | $280,424 |
| Richard C. Riley | | 40% | $335,000 |
| Roderick K. West | 70% | $643,044 | 70% | $659,120 |
Performance Units
| |
(6)(7) | InWith respect to Mr. Denault, in the event of a termination due to death or disability, by Mr. Denault for good reason, or by Entergy Corporation not for cause (in all cases, regardless of whether thereTermination Event, he is a change in control), Mr. Denault would have forfeited his performance units for all open performance periods and would have been entitled to receive a single-lump sumTarget LTIP Award, as defined in his 2006 retention agreement, calculated by 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 employment termination occurs, assuming all performance goals were achieved at target. For purposes of the table, the value of Mr. Denault’s retention payment was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (26,000 units) and the 2012-2014 Performance Unit Program (26,900 units)(26,900) and from the 2013-2015 Performance Unit Program (38,000). This average number of units (26,450 units)(32,450) multiplied by the closing price of Entergy Corporation stock on December 31, 201530, 2016 ($68.36)73.47) would equal a payment of $1,808,122 for$2,384,102. In the forfeited performance units.event of death or disability, Mr. Denault receives the greater of Target LTIP Award calculated as described above or the sum of the amount that would be payable under the provisions of each open Performance Unit Program. |
| |
(7)(8) | In the event of a qualifying termination related to a change in control, each Named Executive Officer would have forfeited his or hertheir performance units for the 2014-2016 and 2015-2017 performance periodsperiod and would have been entitled to receive, pursuant to the 2011 Equity Ownership Plan, a single-lump sum payment that would not be based on any outstanding performance periods.period. For both the 2014-2016 and 2015-2017 performance periods,period, the payment would have been calculated using the average annual number of performance units he or shethey would have been entitled to receive under each Performance Unit Program with respect to the two most recent performance periods preceding (but not including) the calendar year in which his or hertheir termination occurs, assuming all performance goals were achieved at target multiplied by the closing price of Entergy Corporation stock on December 31, 2015.30, 2016. For purposes of the table, the value of Mr. Denault’s payment was calculated by taking an average of the target performance units from the 2012-2014 Performance Unit Program (26,900) and 2013-2015 Performance Unit Program (38,000). This average number of units (32,450) multiplied by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47) would equal a payment of $2,384,102 for the forfeited performance units. |
severance payment was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (26,000 units) and the 2012-2014 Performance Unit Program (26,900 units). This average number of units (26,450 units) multiplied by the closing price of Entergy Corporation stock on December 31, 2015 ($68.36) would equal a severance payment of $1,808,122 for the forfeited performance units.
The value of the severance payment for Mr. Bunting, Mr.Messrs. Marsh, Bakken, and Mr. West was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (5,900 units) and the 2012-2014 Performance Unit Program (5,400 units)(5,400) and 2013-2015 Performance Unit Program (7,600). This average number of units (5,650 units)(6,500) multiplied by the closing price of Entergy Corporation stock on December 31, 201530, 2016 ($68.36)73.47) would equal a severance payment of $386,234$477,555 for the forfeited performance units.
The value of the severance payment for Mr. May was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (2,500 units) and the 2012-2014 Performance Unit Program (2,400 units)(2,400) and 2013-2015 Performance Unit Program (3,000). This average number of units (2,450 units)(2,700) multiplied by the closing price of Entergy Corporation stock on December 31, 201530, 2016 ($68.36)73.47) would equal a severance payment of $167,482$198,369 for the forfeited performance units.
The value of the severance payment for Mr.Messrs. Fisackerly, Mr. McDonald,Rice, Riley, and Ms. Rainer and Mr. Rice was calculated by taking an average of the target performance units from the 2011-2013 Performance Unit Program (1,200 units) and the 2012-2014 Performance Unit Program (1,500 units)(1,500) and 2013-2015 Performance Unit Program (1,900). This average number of units (1,350 units)(1,700) multiplied by the closing price of Entergy Corporation stock on December 31, 201530, 2016 ($68.36)73.47) would equal a severance payment of $92,286$124,899 for the forfeited performance units.
In the event of death or disability, other thana qualifying termination related to a change in control, each Named Executive Officer would have forfeited his performance units for the 2016-2018 performance period and would have been entitled to receive, pursuant to the 2015 Equity Ownership Plan, a single-lump sum payment that would not be based on any outstanding performance period. The 2016-2018 performance period payment would have been calculated using the most recent performance period preceding (but not including) the calendar year in which termination occurs. For purposes of the table, the value of Mr. Denault, orDenault’s payment was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (38,000) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $2,791,860 for the forfeited performance units.
The value of the payment for Messrs. Marsh, Bakken, and West was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (7,600) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $558,372 for the forfeited performance units.
The value of the payment for Mr. May was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (3,000) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $220,410 for the forfeited performance units. The value of the payment for Messrs. Fisackerly, Rice, Riley, and Ms. Rainer was calculated by multiplying the target performance units for the 2013-2015 Performance Unit Program (1,900) by the closing price of Entergy Corporation stock on December 30, 2016 ($73.47), which would equal a payment of $139,593 for the forfeited performance units.
In the event of retirement in the case of Mr. Denault, Mr. Bunting,Brown, or Ms. Rainer, or upon death or disability, other than Mr. McDonald,Denault, each Named Executive Officer would not have forfeited his or hertheir performance units for all open performance periods, but rather such performance unit awards would have been pro-rated based on his or hertheir number of months of participation in each open Performance Unit Program performance cycle,period, in accordance with his or hertheir grant agreement under the Performance Unit Program. 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 valuevalues of the awards waswere calculated as follows:
Mr. Denault’s:
2014 - 2016 Plan - 26,667 (24/36*40,000) performance units at target, assuming a stock price of $68.36
2015 - 2017 Plan - 11,033 (12/22,067 (24/36*33,100) performance units at target, assuming a stock price of $68.36$73.47
Messrs. Bunting’s, Marsh’s, and Mr. West’s:
20142016 - 20162018 Plan - 6,267 (24/13,900 (12/36*9,400)41,700) performance units at target, assuming a stock price of $68.36$73.47
Mr. Bakken’s:
2015 - 2017 Plan - 2,1832,426 (24/36*3,639) performance units at target, assuming a stock price of $73.47
2016 - 2018 Plan - 2,430 (12/36*7,289) performance units at target, assuming a stock price of $73.47
Messrs. Brown’s, Marsh’s, and West’s:
2015 - 2017 Plan - 4,367 (24/36*6,550) performance units at target, assuming a stock price of $68.36$73.47
Mr. May’s:
20142016 - 20162018 Plan - 2,067 (24/2,733 (12/36*3,100)8,200) performance units at target, assuming a stock price of $68.36$73.47
Mr. May’s:
2015 - 2017 Plan - 683 (12/1,367 (24/36*2,050) performance units at target, assuming a stock price of $68.36$73.47
Mr. Fisackerly’s, Mr. McDonald’s, Ms. Rainer’s, and Mr. Rice’s:
20142016 - 20162018 Plan - 1,467 (24/900 (12/36*2,200)2,700) performance units at target, assuming a stock price of $68.36$73.47
Messrs. Fisackerly’s, Rice’s, Riley’s, and Ms. Rainer’s:
2015 - 2017 Plan - 483 (12/967 (24/36*1,450) performance units at target, assuming a stock price of $68.36$73.47
2016 - 2018 Plan - 600 (12/36*1,800) performance units at target, assuming a stock price of $73.47
Unvested Stock Options
| |
(8)(9) | In the event of death or disability or qualifying termination related to a change in control or retirement in the case of Mr. Denault, Mr. Bunting,Brown, or Mr. McDonald,Ms. Rainer, all of the unvested stock options of each Named Executive Officer would immediately vest pursuant to the 2011 Equity Ownership Plan and 2015 Equity Ownership Plan. In addition, with respect to grants under the 2011 Equity Ownership Plan, each Named Executive Officer would be entitled to exercise their stock options for the remainder of the ten-year period extending from the grant date of the options, and with respect to grants under the 2015 Equity Ownership Plan, within the lesser of five years or the remaining term of the option grant. For purposes of this table, it is assumed that the Named Executive Officers exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of common stock on December 30, 2016, and the applicable exercise price of each option share. |
entitled to exercisea Termination Event as defined in his or her2006 retention agreement, Mr. Denault would immediately vest in all unvested stock options for the remainder of the ten-year period extending from the grant date of the options. For purposes of this table, it is assumed that the Named Executive Officers exercised their options immediately upon vesting and received proceeds equal to the difference between the closing price of Entergy Corporation common stock on December 31, 2015, and the applicable exercise price of each option share.
| |
| (10) | When Mr. McDonald retired all of his unvested stock options immediately vested. In addition, Mr. McDonald is entitled to exercise any outstanding options during the ten-year term extending from the grant date of the options. For purposes of this table, we 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 30, 2016, and the exercise price of each option share. |
Unvested Restricted Stock
| |
(9)(11) | In the event of death or disability (pursuant to the 2011 Equity Ownership Plan), each Named Executive Officer would immediately vest in a pro-rated portion of his or hertheir 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) pursuant to the 2011 Equity Ownership Plan. 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 or hertheir death or disability. In the event of his or hera qualifying termination related to a change in control, the Named Executive OfficersOfficer would immediately vest in all of their unvested restricted stock (as well as dividends declared on the pro-rated portion of such restricted stock). In the event of death, disability, or qualifying termination related to a change in control (pursuant to the 2015 Equity Ownership Plan), each Named Executive Officer would vest in all of their unvested restricted stock (as well as dividends declared). |
In the event of a Termination Event as defined in his 2006 retention agreement, Mr. Denault would immediately vest in all unvested restricted stock.
Welfare Benefits
| |
(10)(12) | Upon retirement, Mr. Denault, Mr. Bunting,Brown, and Mr. McDonaldMs. Rainer would be eligible for retiree medical and dental 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, Messrs.Mr. Denault, Bunting,Mr. Brown, and McDonaldMs. Rainer would not be eligible to receive Entergy Corporation subsidized COBRA benefits. Upon his retirement, Mr. McDonald receives retiree medical and dental benefits, the same as all other retirees. |
| |
(11)(13) | Pursuant to the System Executive Continuity Plan, in the event of a termination related to a change in control, Mr.Messrs. Bakken, Marsh, Mr. May, and Mr. West would be eligible to receive Entergy Corporation-subsidizedsubsidized COBRA benefits for 18 months and Mr.Messrs. Fisackerly, Ms. Rainer,Rice, and Mr. RiceRiley would be eligible to receive Entergy Corporation-subsidizedsubsidized COBRA benefits for 12 months. |
Restricted Stock Units
| |
(12)(14) | Mr. Bakken’s 30,000 restricted stock units vest one third (1/3rd) on each of April 6, 2019, April 6, 2022 and April 6, 2025. Pursuant to his restricted stock unit agreement, if Mr. Bakken’s employment terminates due to total disability or death or, prior to April 6, 2019, Mr. Bakken’s employment is terminated by his Entergy employer other than for cause, then he will vest in and be paid the 10,000 restricted stock units that otherwise would have vested had he satisfied the vesting conditions of the restricted stock unit agreement through the next vesting date to occur following his date of total disability, death or termination other than for cause prior to April 6, 2019 subject, in the case of a termination without cause, to Mr. Bakken timely executing and not revoking a release of claims against Entergy Corporation and its affiliates. In the event of a change in control, the unvested restricted stock units will fully vest upon Mr. Bakken’s termination of employment by his employer without cause or by Mr. Bakken with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Bakken voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Bakken is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates or solicit its employees or customers during and for 12 months after his employment with his Entergy employer. In addition, the restricted stock unit agreement limits Mr. Bakken’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions other than following certain constructive terminations of his employment, Mr. Bakken will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares. |
| |
| (15) | Mr. Marsh’s 21,100 restricted stock units vest 100% in 2020. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of his termination of employment due to Mr. Marsh’s total disability or death. In the event of a change in control, the units will vest upon termination of Mr. Marsh’s employment by his Entergy Corporationemployer without cause or by Mr. Marsh with good reason during a change in control period (as defined in the 2015 Equity Ownership Plan). Otherwise, if Mr. Marsh voluntarily resigns or is terminated, he would forfeit these units. Pursuant to his restricted stock unit agreement, Mr. Marsh is subject to certain restrictions on his ability to compete with Entergy Corporation and its affiliates during and for 12 months after his employment, or to solicit its employees or customers during and for 24 months after his employment. In addition, the restricted stock unit agreement limits Mr. Marsh’s ability to disparage Entergy Corporation and its affiliates. In the event of a breach of these restrictions, Mr. Marsh will forfeit any restricted stock units that are not yet vested and paid, and must repay to Entergy Corporation any shares of Entergy Corporation stock paid to him in respect of the restricted stock units and any amounts he received upon the sale or transfer of any such shares. |
| |
(13)(16) | Mr. West’s 21,000 restricted stock units vest 100% in 2018. Pursuant to his restricted stock unit agreement, any unvested restricted stock units will vest immediately in the event of a termination for a reason other than cause, total disability or death. In the event of a change in control, the units will vest upon termination of Mr. West’s employment by his Entergy Corporationemployer without cause or by Mr. West with good reason during a change in control period (as defined in the 2011 Equity Ownership Plan). IfOtherwise, if Mr. West voluntarily resigns, or is terminated for cause, dies or becomes disabled, he would forfeit these units. |
Mr. Denault’s 2006 Retention Agreement
Under the terms of Mr. Denault’s 2006 retention agreement, his Entergy Corporationemployer 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 Corporation;
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 Corporation’s reputation;
material violation of any agreement that he has entered into with Entergy Corporation; or
unauthorized disclosure of Entergy Corporation’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 from those in effect immediately prior to the date of the retention agreement, other than de minimis acts that are remedied after notice from Mr. Denault;
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 or her under any of Entergy Corporation’s pension, savings, life insurance, medical, health and accident, disability or vacation plans or policies 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.
System Executive Continuity Plan
Termination Related to a Change in Control
The Named Executive Officers will be entitled to the benefits described in the tables above under the System Executive Continuity Plan in the event of a termination related to a change in control if a change in control occurs and their employment is terminated by antheir Entergy System companyemployer other than for cause or if they terminate their employment for good reason, in each case within a period beginning on the occurrence of a potential change in control and ending 24 months following the effective date of a change in control.
A change in control includes the following events:
The
the purchase of 30% or more of either Entergy CorporationCorporation’s common stock or the combined voting power of itsEntergy Corporation’s voting securities;
the merger or consolidation of Entergy Corporation (unless its Board members constitute at least a majority of the board members of the surviving 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 theEntergy Corporation’s Board at the end of the period.
A potential change in control includes the following events:
Entergy Corporation or an affiliate enters into an agreement the consummation of which would constitute a change in control;
the Entergy Corporation Board adopts resolutions determining that, for purposes of the System Executive Continuity Plan, a potential change in control has occurred;
an Entergy System CompanyCorporation affiliate or other person or entity publicly announces an intention to take actions that would constitute a change in control; or
any person or entity becomes the beneficial owner (directly or indirectly) of outstanding shares of Entergy Corporation’s common stock of Entergy Corporation constituting 20% or more of the voting power or value of Entergy Corporation’s outstanding common stock.
A Named Executive Officer’s employment may be terminated for cause under the System Executive Continuity Plan if he or she:
willfully and continuously fails to substantially perform his or her duties after receiving a 30-day written demand for performance from theEntergy Corporation’s Board;
engages in conduct that is materially injurious to Entergy Corporation or any of its subsidiaries;
is convicted or pleads guilty or nolo contendere 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;
materially violates any agreement with Entergy Corporation or any of its subsidiaries; or
discloses any of Entergy CorporationCorporation’s confidential information without authorization.
A Named Executive Officer may terminate his or her employment with anhis or her Entergy System Companyemployer for good reason under the System Executive Continuity Plan if, without his or her 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 his or her 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 Entergy employer purports to terminate his or her employment other than in accordance with the System Executive Continuity Plan.
In addition to participation in the System Executive Continuity Plan, benefits already accrued under the System Executive Retirement Plan, Pension Equalization Plan, and Supplemental RetirementCash Balance Equalization Plan, if any, will become fully vested if the executive is involuntarily terminated without cause or the executive terminates his or her employment for good reason within two years after the occurrence of a change in control. Any awards granted under the equity ownership plansEquity Ownership Plans will become fully vested if the executive is involuntarily terminated without cause or terminates employment for good reason within two years after the occurrence of a change in control. In 2010, Entergy Corporation eliminated tax gross up payments for any severance benefits paid under the System Executive Continuity Plan.
Under certain circumstances described below, 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 his or her non-competitionnon-compete 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 his or her non-competitionnon-compete 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 Plan 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,” except that all options are no longer exercisable.
Voluntary Resignation
If a Named Executive Officer voluntarily resigns, from his or her Entergy System company employer, he or she is entitled to all vested 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 our 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 any outstanding performance periods under the Long-Term Performance Unit Program or the Annual Incentive Plan. If the officer resigns after the completion of an Annual Incentive Plan or Long-Term Performance Unit Program performance period, he or she could receive a payout under the Long-Term Performance Unit Program based on the outcome of the performance cycleperiod and could, at the Company’sEntergy Corporation’s discretion, receive an annual incentive payment under the Annual 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 our retirement plans,the Entergy Retirement Plan, 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 planEntergy 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 the Entergy System company employer.
Upon a Named Executive Officer’s retirement, he or she is generally entitled to all vested 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 Annual 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 Long-Term Performance Unit Program for those retiring with a minimum 12 months of participation are pro-rated based on the actual full months of participation, in each outstanding performance cycle,period, in which the retirement date occurs. In each case, payments are delivered at the conclusion of each annual or performance cycle,period, consistent with the timing of payments to active participants in the Annual Incentive Plan and the Long-Term Performance Unit Program, respectively. Unvested stock options issued under our equity ownership plansthe 2011 Equity Ownership Plan vest on the retirement date and expire ten years from the grant date of the options. Unvested stock options issued under the 2015 Equity Ownership Plan expire the lesser of five years from the grant date of the options or original term of ten years. Any unvested restricted stock and restricted stock units (other than those issued under the Long-Term Performance Unit Program) held by the executive upon his or her retirement are forfeited, and perquisites 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 unvested restricted stock and restricted stock 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.“Retirement,” except that unvested restricted stock and restricted stock units may be subject to specific death benefits (as noted, where applicable, in the tables above).
For information regarding compensation of the directors of Entergy Corporation, see the Proxy Statement under the heading “Director Compensation,” which information is incorporated herein by reference. The Boards of Directors of Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas are comprised solely of employee directors who receive no compensation for service as directors.
Item 12. Security Ownership of Certain Beneficial Owners and Management
Entergy Corporation owns 100% of the outstanding common stock of registrants Entergy Arkansas, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and indirectly 100% of the outstanding common membership interests of registrant Entergy Louisiana. The information with respect to persons known by Entergy Corporation to
be beneficial owners of more than 5% of Entergy Corporation’s outstanding common stock is included under the heading “Persons Owning“Entergy Share Ownership - Beneficial Owners of More Than Five Percent of Entergy Common Stock”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 Stockcommon stock of Entergy Corporation and stock-based units as of January 31, 20162017 for all non-employee directors and Named Executive Officers. Unless otherwise noted, each person had sole voting and investment power over the number of shares of Common Stockcommon stock and stock-based units of Entergy Corporation set forth across from his or her name.
| | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Corporation | | | | | | | | | | | | |
| A. Christopher Bakken, III** | | | 5,200 |
| | — |
| | — |
|
| Maureen S. Bateman* | | 19,053 |
| | — |
| | — |
| | 20,924 |
| | — |
| | — |
|
| Theodore H. Bunting, Jr.** | | 20,932 |
| | 136,833 |
| | — |
| |
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Patrick J. Condon* | | 797 |
| | — |
| | — |
| | 2,668 |
| | — |
| | — |
|
| Leo P. Denault*** | | 86,985 |
| | 409,999 |
| | — |
| | 111,638 |
| | 470,332 |
| | — |
|
| Kirkland H. Donald* | | 3,309 |
| | — |
| | — |
| | 4,662 |
| | — |
| | 609 |
|
| Gary W. Edwards* | | 9,754 |
| | — |
| | 4,506 |
| |
| Philip L. Frederickson* | | 191 |
| | — |
| | — |
| | 1,159 |
| | — |
| | 609 |
|
| Alexis Herman* | | 10,969 |
| | — |
| | — |
| |
| Alexis M. Herman* | | | 11,766 |
| | — |
| | — |
|
| Donald C. Hintz* | | 12,672 |
| | — |
| | 3,156 |
| | 13,907 |
| | — |
| | 3,973 |
|
| Stuart L. Levenick* | | 14,384 |
| | — |
| | — |
| | 16,255 |
| | — |
| | — |
|
| Blanche L. Lincoln* | | 6,951 |
| | — |
| | — |
| | 9,000 |
| | — |
| | — |
|
| Andrew S. Marsh** | | 46,180 |
| | 109,433 |
| | — |
| | 54,067 |
| | 139,100 |
| | — |
|
| William M. Mohl** | | 19,241 |
| | 107,133 |
| | — |
| |
| Karen A. Puckett* | | 797 |
| | — |
| | — |
| | 2,668 |
| | — |
| | — |
|
| W. J. Tauzin* | | 14,146 |
| | — |
| | — |
| | 16,017 |
| | — |
| | — |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
| | 36,509 |
| | 90,999 |
| | — |
|
| Steven V. Wilkinson* | | 16,835 |
| | — |
| | — |
| |
| All directors and executive | | | | | | | | | | | | |
| officers as a group (22 persons) | | 389,062 |
| | 1,159,028 |
| | 7,662 |
| |
| officers as a group (21 persons) | | | 429,753 |
| | 1,240,862 |
| | 5,191 |
|
| | | | | | | | | | | | | |
| Entergy Arkansas | | | |
| | |
| | |
|
| A. Christopher Bakken, III** | | | 5,200 |
| | — |
| | — |
|
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Leo P. Denault** | | | 111,638 |
| | 470,332 |
| | — |
|
| Andrew S. Marsh*** | | | 54,067 |
| | 139,100 |
| | — |
|
| Richard C. Riley*** | | | 10,700 |
| | 19,734 |
| | — |
|
| Roderick K. West** | | | 36,509 |
| | 90,999 |
| | — |
|
| All directors and executive | | | | | | | |
| officers as a group (11 persons) | | | 320,062 |
| | 1,117,630 |
| | — |
|
|
| | | | | | | | | |
Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Arkansas | | |
| | |
| | |
|
| Theodore H. Bunting, Jr.*** | | 20,932 |
| | 136,833 |
| | — |
|
| Leo P. Denault** | | 86,985 |
| | 409,999 |
| | — |
|
| Paul D. Hinnenkamp* | | 15,335 |
| | 48,732 |
| | — |
|
| Andrew S. Marsh*** | | 46,180 |
| | 109,433 |
| | — |
|
| Hugh T. McDonald*** | | 16,031 |
| | 46,466 |
| | — |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 275,994 |
| | 1,098,361 |
| | — |
|
| | | | | | | |
| Entergy Louisiana | | | | | | |
| Theodore H. Bunting, Jr.*** | | 20,932 |
| | 136,833 |
| | — |
|
| Leo P. Denault** | | 86,985 |
| | 409,999 |
| | — |
|
| Paul D. Hinnenkamp* | | 15,335 |
| | 48,732 |
| | — |
|
| Andrew S. Marsh*** | | 46,180 |
| | 109,433 |
| | — |
|
| Phillip R. May, Jr.*** | | 14,664 |
| | 42,699 |
| | 11 |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (10 persons) | | 274,627 |
| | 1,094,594 |
| | 11 |
|
| | | | | | | |
| Entergy Mississippi | | | | | | |
| Theodore H. Bunting, Jr.*** | | 20,932 |
| | 136,833 |
| | — |
|
| Leo P. Denault** | | 86,985 |
| | 409,999 |
| | — |
|
| Haley R. Fisackerly*** | | 7,801 |
| | 30,167 |
| | — |
|
| Paul D. Hinnenkamp* | | 15,335 |
| | 48,732 |
| | — |
|
| Andrew S. Marsh*** | | 46,180 |
| | 109,433 |
| | — |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 254,520 |
| | 1,007,096 |
| | — |
|
| | | | | | | |
| Entergy New Orleans | | | | | | |
| Theodore H. Bunting, Jr.*** | | 20,932 |
| | 136,833 |
| | — |
|
| Leo P. Denault** | | 86,985 |
| | 409,999 |
| | — |
|
| Paul D. Hinnenkamp* | | 15,335 |
| | 48,732 |
| | — |
|
| Andrew S. Marsh*** | | 46,180 |
| | 109,433 |
| | — |
|
| Charles L. Rice, Jr.*** | | 5,477 |
| | 17,466 |
| | — |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
|
| All directors and executive | | | | | | |
| officers as a group (9 persons) | | 252,196 |
| | 994,395 |
| | — |
|
| | Name | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) | | Shares (1)(2) | | Options Exercisable Within 60 Days | | Stock Units (3) |
| Entergy Louisiana | | | | | | | |
| A. Christopher Bakken, III** | | | 5,200 |
| | — |
| | — |
|
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Leo P. Denault** | | | 111,638 |
| | 470,332 |
| | — |
|
| Andrew S. Marsh*** | | | 54,067 |
| | 139,100 |
| | — |
|
| Phillip R. May, Jr.*** | | | 16,599 |
| | 45,233 |
| | 12 |
|
| All directors and executive | | | | | | | |
| officers as a group (11 persons) | | | 325,961 |
| | 1,143,129 |
| | 12 |
|
| | | | | | | | |
| Entergy Mississippi | | | | | | | |
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Leo P. Denault** | | | 111,638 |
| | 470,332 |
| | — |
|
| Haley R. Fisackerly*** | | | 6,749 |
| | 31,401 |
| | — |
|
| Andrew S. Marsh*** | | | 54,067 |
| | 139,100 |
| | — |
|
| Roderick K. West** | | | 36,509 |
| | 90,999 |
| | — |
|
| All directors and executive | | | | | | | |
| officers as a group (10 persons) | | | 310,911 |
| | 1,129,297 |
| | — |
|
| | | | | | | | |
| Entergy New Orleans | | | | | | | |
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Leo P. Denault** | | | 111,638 |
| | 470,332 |
| | — |
|
| Andrew S. Marsh*** | | | 54,067 |
| | 139,100 |
| | — |
|
| Charles L. Rice, Jr.*** | | | 5,834 |
| | 14,467 |
| | — |
|
| Roderick K. West** | | | 36,509 |
| | 90,999 |
| | — |
|
| All directors and executive | | | | | | | |
| officers as a group (10 persons) | | | 309,996 |
| | 1,112,363 |
| | — |
|
| | | | | | | | |
| Entergy Texas | | | | | | | | | | | | |
| Theodore H. Bunting, Jr.*** | | 20,932 |
| | 136,833 |
| | — |
| |
| Marcus V. Brown** | | | 29,528 |
| | 101,700 |
| | — |
|
| Leo P. Denault** | | 86,985 |
| | 409,999 |
| | — |
| | 111,638 |
| | 470,332 |
| | — |
|
| Paul D. Hinnenkamp* | | 15,335 |
| | 48,732 |
| | — |
| |
| Andrew S. Marsh*** | | 46,180 |
| | 109,433 |
| | — |
| | 54,067 |
| | 139,100 |
| | — |
|
| Sallie T. Rainer*** | | 10,267 |
| | 18,932 |
| | — |
| | 8,031 |
| | 22,366 |
| | — |
|
| Roderick K. West** | | 31,927 |
| | 133,666 |
| | — |
| | 36,509 |
| | 90,999 |
| | — |
|
| All directors and executive | | | | | | | | | | | | |
| officers as a group (9 persons) | | 256,986 |
| | 995,861 |
| | — |
| |
| officers as a group (10 persons) | | | 312,193 |
| | 1,120,262 |
| | — |
|
|
| |
| * | 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 non-employee directors and executive officers as a group does not exceed one percent of the outstanding shares of Entergy Corporation common stock. |
| |
| (2) | For the non-employee directors, the balances include phantom units that are issued under the Service Recognition Program. All non-employee directors are credited with phantom units for each year of service on the Entergy Corporation Board. These phantom units do not have voting rights, accrue dividends, and will be settled in shares of Entergy Corporation common stock following the non-employee director’s separation from the Board. |
| |
| (3) | 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 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. Messrs. EdwardsDonald, Hintz, and HintzFrederickson have deferred receipt of some of their quarterly stock grants. The deferred shares will be settled in cash in an amount equal to the market value of Entergy Corporation common stock at the end of the deferral period. |
Equity Compensation Plan Information
The following table summarizes the equity compensation plan information as of December 31, 2015.2016. 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) | | 7,399,820 |
| | $84.19 | | 9,485,610 |
| | 7,137,210 |
| | $84.91 | | 5,192,463 |
|
Equity compensation plans not approved by security holders(2) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
| Total | | 7,399,820 |
| | $84.19 | | 9,485,610 |
| | 7,137,210 |
| | $84.91 | | 5,192,463 |
|
| |
| (1) | Includes the Equity Ownership Plan, which was approved by the shareholders on May 15, 1998, the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan. The 2007 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 12, 2006, and 7,000,000 shares of Entergy Corporation common stock were available for issuance, with no more than 2,000,000 shares available for non-option grants. The 2007 Plan only applies to awards granted between January 1, 2007 and May 5, 2011. 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 were available for issuance from the 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants. The 2011 Plan only applied to awards granted between May 6, 2011 and May 7, 2015. The 2015 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 8, 2015, and 6,900,000 shares of Entergy Corporation common stock can be issued from the 2015 Equity Ownership Plan, with no more than 1,500,000 shares available for incentive stock option grants. The 2015 Plan applies to awards granted on or after May 8, 2015. The 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan (the “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 employer and any corporation 80% or more of whose stock (based on voting power) or value is owned, directly or indirectly, by Entergy Corporation. The Plans provide for the issuance of stock options, restricted stock, 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), restricted stock unit awards, and other stock-based awards. |
Ownership Plan was approved by Entergy Corporation shareholders on May 12, 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 2011 Equity Ownership Plan, with no more than 2,000,000 shares available for incentive stock option grants. The 2015 Equity Ownership Plan was approved by Entergy Corporation shareholders on May 8, 2015, and 6,900,000 shares of Entergy Corporation common stock can be issued from the 2015 Equity Ownership Plan, with no more than 1,500,000 shares available for incentive stock option grants. The Equity Ownership Plan, the 2007 Equity Ownership Plan, the 2011 Equity Ownership Plan, and the 2015 Equity Ownership Plan (the “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 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. As of December 31, 2015,2016, all options outstanding under the plan were either exercised or expired. |
Item 13. Certain Relationships and Related Party Transactions and Director Independence
For information regarding certain relationships,relationship, related transactions and director independence of Entergy Corporation, see the Proxy Statement under the headings “Corporate Governance at Entergy - Our Board Structure - Director Independence” and “Transactions“Corporate Governance at Entergy - Other Governance Policies and Practices - Our Transactions with Related Persons,” which information is incorporated herein by reference.
Since January 1, 2015, 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”).Persons Policy.”
Entergy Corporation’s Board of Directors has adopted written policies and procedures for the review, approval or ratification of any transaction involving an amount in excess of $120,000 in which any director or executive officer of Entergy Corporation, any nominee for director, or any immediate family member of the foregoing has or will have a material interest as contemplated by Item 404(a) of Regulation S-K (“Related Party Transactions.Person Transactions”). Under these policies and procedures, theEntergy Corporation’s Corporate Governance Committee or a subcommittee of its Board of Directors consisting entirely 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 that are at least as favorable to Entergy Corporation or the subsidiary as those could be achievedachievable with an unaffiliated third party;
Size of the 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 Transactionsrelated person transactions involving a director or an executive officer solely resulting from that person’s service as a director or employment with Entergy Corporation so long as the compensation is approved by Entergy Corporation’sthe Board of Directors (or an appropriate committee), (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 S-K.
Related Party Transactions
499
None of the Subsidiaries are listed issuers. As previously noted, the Boards of Directors of the Subsidiaries are composed solely of employee directors. None of the Boards of Directors ofSince January 1, 2016, neither Entergy Corporation nor any of the Subsidiariesits affiliates has participated in any committees.Related Person Transaction.
Item 14. Principal Accountant Fees and Services (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
Aggregate fees billed to Entergy Corporation (consolidated), Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy for the years ended December 31, 20152016 and 20142015 by Deloitte & Touche LLP were as follows:
| | | | 2015 | | 2014 | 2016 | | 2015 |
| Entergy Corporation (consolidated) | | | | | | |
| Audit Fees |
| $9,312,255 |
| |
| $8,097,000 |
|
| $8,932,000 |
| |
| $9,312,255 |
|
| Audit-Related Fees (a) | 970,000 |
| | 1,135,000 |
| 865,000 |
| | 970,000 |
|
| Total audit and audit-related fees | 10,282,255 |
| | 9,232,000 |
| 9,797,000 |
| | 10,282,255 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $10,282,255 |
| |
| $9,232,000 |
|
| $9,797,000 |
| |
| $10,282,255 |
|
| Entergy Arkansas | | | | | | |
| Audit Fees |
| $954,813 |
| |
| $984,813 |
|
| $1,056,881 |
| |
| $954,813 |
|
| Audit-Related Fees (a) | — |
| | 19,000 |
| — |
| | — |
|
| Total audit and audit-related fees | 954,813 |
| | 1,003,813 |
| 1,056,881 |
| | 954,813 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $954,813 |
| |
| $1,003,813 |
|
| $1,056,881 |
| |
| $954,813 |
|
| Entergy Louisiana | | | | | | |
| Audit Fees |
| $1,873,042 |
| |
| $2,009,626 |
|
| $2,138,762 |
| |
| $1,873,042 |
|
| Audit-Related Fees (a) | 390,000 |
| | 750,000 |
| 450,000 |
| | 390,000 |
|
| Total audit and audit-related fees | 2,263,042 |
| | 2,759,626 |
| 2,588,762 |
| | 2,263,042 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $2,263,042 |
| |
| $2,759,626 |
|
| $2,588,762 |
| |
| $2,263,042 |
|
| Entergy Mississippi | | | | | | |
| Audit Fees |
| $824,813 |
| |
| $869,813 |
|
| $971,881 |
| |
| $824,813 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 824,813 |
| | 869,813 |
| 971,881 |
| | 824,813 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $824,813 |
| |
| $869,813 |
|
| $971,881 |
| |
| $824,813 |
|
| | | | 2015 | | 2014 | 2016 | | 2015 |
| Entergy New Orleans | | | | | | |
| Audit Fees |
| $977,652 |
| |
| $824,813 |
|
| $1,056,881 |
| |
| $977,652 |
|
| Audit-Related Fees (a) | 225,000 |
| | — |
| — |
| | 225,000 |
|
| Total audit and audit-related fees | 1,202,652 |
| | 824,813 |
| 1,056,881 |
| | 1,202,652 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $1,202,652 |
| |
| $824,813 |
|
| $1,056,881 |
| |
| $1,202,652 |
|
| Entergy Texas | | | | | | |
| Audit Fees |
| $1,643,813 |
| |
| $1,004,813 |
|
| $1,076,881 |
| |
| $1,643,813 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 1,643,813 |
| | 1,004,813 |
| 1,076,881 |
| | 1,643,813 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $1,643,813 |
| |
| $1,004,813 |
|
| $1,076,881 |
| |
| $1,643,813 |
|
| System Energy | | | | | | |
| Audit Fees |
| $824,813 |
| |
| $824,813 |
|
| $861,881 |
| |
| $824,813 |
|
| Audit-Related Fees (a) | — |
| | — |
| — |
| | — |
|
| Total audit and audit-related fees | 824,813 |
| | 824,813 |
| 861,881 |
| | 824,813 |
|
| Tax Fees | — |
| | — |
| — |
| | — |
|
| All Other Fees | — |
| | — |
| — |
| | — |
|
| Total Fees (b) |
| $824,813 |
| |
| $824,813 |
|
| $861,881 |
| |
| $824,813 |
|
| |
| (a) | Includes fees for employee benefit plan audits, consultation on financial accounting and reporting, and other attestation services. |
| |
| (b) | 100% of fees paid in 20152016 and 20142015 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’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’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
Item 15. Exhibits and Financial Statement Schedules
|
| |
| (a)1. | Financial Statements and Independent Auditors’ Reports for Entergy, Entergy Arkansas, 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 513)519) |
| | |
| | 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 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. |
Item 16. Form 10-K Summary (Entergy Corporation, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, Entergy Texas, and System Energy)
None.
ENTERGY CORPORATION
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Leo P. Denault (Chairman of the Board, Chief Executive Officer and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President and Chief Financial Officer; Principal Financial Officer); Maureen S. Bateman, Patrick J. Condon, Kirkland H. Donald, Gary W. Edwards, Philip L. Frederickson, Alexis M. Herman, Donald C. Hintz, Stuart L. Levenick, Blanche L. Lincoln, Karen A. Puckett, and W. J. Tauzin and Steven V. Wilkinson (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Hugh T. McDonaldRichard C. Riley (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Phillip R. May, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Haley R. Fisackerly (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Charles L. Rice, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Sallie T. Rainer (Chair of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); Theodore H. Bunting, Jr. and Paul D. Hinnenkamp (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
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/ Alyson M. Mount |
| | Alyson M. Mount |
| | Senior Vice President and Chief Accounting Officer |
| | |
| | Date: February 25, 201624, 2017 |
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/ Alyson M. Mount Alyson M. Mount | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 25, 201624, 2017 |
Theodore H. Bunting, Jr. (Chairman of the Board, President, Chief Executive Officer, and Director; Principal Executive Officer); Andrew S. Marsh (Executive Vice President, Chief Financial Officer, and Director; Principal Financial Officer); A. Christopher Bakken, III and Steven C. McNeal and Timothy G. Mitchell (Directors).
|
| |
By: /s/ Alyson M. Mount | February 25, 201624, 2017 |
| (Alyson M. Mount, Attorney-in-fact) | |
EXHIBIT 23(a)
CONSENTS OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
We consent to the incorporation by reference in Registration Statement No. 333-190911333-213335 on Form S-3 and in Registration Statements Nos. 333-75097, 333-140183, 333-90914, 333-174148, 333-206556, and 333-204546 on Form S-8 of our reports dated February 25, 2016,24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Corporation and Subsidiaries, 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 for the year ended December 31, 2015.2016.
We consent to the incorporation by reference in Registration Statement No. 333-190911-02333-213335-06 on Form S-3 of our reports dated February 25, 2016,24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Arkansas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Arkansas, Inc. for the year ended December 31, 2015.2016.
We consent to the incorporation by reference in Registration Statement No. 333-190911-07333-213335-03 on Form S-3 of our reports dated February 25, 2016,24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Louisiana, LLC and Subsidiaries (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the business combination with Entergy Gulf States Louisiana, L.L.C.) appearing in this Annual Report on Form 10‑K of Entergy Louisiana, LLC for the year ended December 31, 2015.2016.
We consent to the incorporation by reference in Registration Statement No. 333-190911-06333-213335-02 on Form S-3 of our reports dated February 25, 2016,24, 2017, relating to the financial statements and financial statement schedule of Entergy Mississippi, Inc. appearing in this Annual Report on Form 10-K of Entergy Mississippi, Inc. for the year ended December 31, 2015.2016.
We consent to the incorporation by reference in Registration Statement No. 333-190911-05333-213335-05 on Form S-3 of our reports dated February 25, 2016, relating to the consolidated financial statements and financial statement schedule of Entergy New Orleans, Inc. and Subsidiaries (which report expresses an unqualified opinion and includes an explanatory paragraph relating to the Algiers asset transfer which was accounted for as a business combination under common control) appearing in this Annual Report on Form 10-K of Entergy New Orleans, Inc. for the year ended December 31, 2015.
We consent to the incorporation by reference in Registration Statement No. 333-190911-04 on Form S-3 of our reports dated February 25, 2016,24, 2017, relating to the consolidated financial statements and financial statement schedule of Entergy Texas, Inc. and Subsidiaries appearing in this Annual Report on Form 10-K of Entergy Texas, Inc. for the year ended December 31, 2015.2016.
We consent to the incorporation by reference in Registration Statement No. 333-190911-03333-213335-04 on Form S-3 of our report dated February 25, 2016,24, 2017, relating to the financial statements of System Energy Resources, Inc. appearing in this Annual Report on Form 10-K of System Energy Resources, Inc. for the year ended December 31, 2015.2016.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
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 consolidated financial statements of Entergy Corporation and Subsidiaries (the “Corporation”) as of December 31, 20152016 and 2014,2015, and for each of the three years in the period ended December 31, 2015,2016, and the Corporation’s internal control over financial reporting as of December 31, 2015,2016, and have issued our reports thereon dated February 25, 2016;24, 2017; such consolidated financial statements and reports are included elsewhere in this Form 10-K. Our audits also included the consolidated financial statement schedule of the Corporation listed in Item 15. This consolidated financial statement schedule is the responsibility of the Corporation’s management. Our responsibility is to express an opinion based on our audits. In our opinion, such consolidated financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.
/s/ DELOITTE & TOUCHE LLP
New Orleans, Louisiana
February 25, 201624, 2017
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Shareholders of
Entergy Arkansas, Inc. and Subsidiaries
Entergy Mississippi, Inc.
Entergy New Orleans, Inc. and Subsidiaries
Entergy Texas, Inc. and Subsidiaries
To the Board of Directors and Members of
Entergy Louisiana, LLC and Subsidiaries
We have audited the consolidated financial statements of Entergy Arkansas, Inc. and Subsidiaries, Entergy Louisiana, LLC and Subsidiaries, Entergy New Orleans, Inc. and Subsidiaries, and Entergy Texas, Inc. and Subsidiaries, and we have also audited the financial statements of Entergy Mississippi, Inc. (collectively the “Companies”) as of December 31, 20152016 and 2014,2015, and for each of the three years in the period ended December 31, 2015,2016, and have issued our reports thereon dated February 25, 2016;24, 2017; such financial statements and reports are included elsewhere in this Form 10-K. Our report on the financial statements of Entergy Louisiana, LLC expresses an unqualified opinion and includes an explanatory paragraph regarding its business combination with Entergy Gulf States Louisiana, L.L.C. Our report on the financial statements of Entergy New Orleans, Inc. expresses an unqualified opinion and includes an explanatory paragraph regarding Entergy Louisiana, LLC’s transfer of its Algiers assets to Entergy New Orleans, Inc. Our audits also included the financial statement schedules of the respective Companies listed in Item 15. These financial statement schedules are the responsibility of the respective Companies’ managements.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 25, 201624, 2017
INDEX TO FINANCIAL STATEMENT SCHEDULES
|
| | |
| Schedule | | Page |
| | | |
| II | Valuation and Qualifying Accounts 2016, 2015, 2014, and 2013:2014: | |
| | Entergy Corporation and Subsidiaries | |
| | Entergy Arkansas, Inc. and Subsidiaries | |
| | Entergy Louisiana, LLC and Subsidiaries | |
| | Entergy Mississippi, Inc. | |
| | Entergy New Orleans, Inc. and Subsidiaries | |
| | Entergy Texas, Inc. and Subsidiaries | |
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, 2015, 2014, and 2013 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2015 | |
| $35,663 |
| |
| $6,926 |
| |
| $2,694 |
| |
| $39,895 |
|
| 2014 | |
| $34,311 |
| |
| $4,573 |
| |
| $3,221 |
| |
| $35,663 |
|
| 2013 | |
| $31,956 |
| |
| $2,355 |
| |
| $— |
| |
| $34,311 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2015, 2014, and 2013 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2015 | |
| $32,247 |
| |
| $2,759 |
| |
| $780 |
| |
| $34,226 |
|
| 2014 | |
| $30,113 |
| |
| $2,881 |
| |
| $747 |
| |
| $32,247 |
|
| 2013 | |
| $28,343 |
| |
| $1,770 |
| |
| $— |
| |
| $30,113 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2015, 2014, and 2013 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2015 | |
| $1,609 |
| |
| $3,464 |
| |
| $864 |
| |
| $4,209 |
|
| 2014 | |
| $1,874 |
| |
| $842 |
| |
| $1,107 |
| |
| $1,609 |
|
| 2013 | |
| $1,578 |
| |
| $296 |
| |
| $— |
| |
| $1,874 |
|
| 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, 2015, 2014, and 2013 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2015 | |
| $873 |
| |
| $247 |
| |
| $402 |
| |
| $718 |
|
| 2014 | |
| $906 |
| |
| $269 |
| |
| $302 |
| |
| $873 |
|
| 2013 | |
| $910 |
| |
| ($4 | ) | |
| $— |
| |
| $906 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2015, 2014, and 2013 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2015 | |
| $262 |
| |
| $217 |
| |
| $211 |
| |
| $268 |
|
| 2014 | |
| $974 |
| |
| $99 |
| |
| $811 |
| |
| $262 |
|
| 2013 | |
| $446 |
| |
| $528 |
| |
| $— |
| |
| $974 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
| | | ENTERGY TEXAS, INC. AND SUBSIDIARIES | |
| ENTERGY CORPORATION AND SUBSIDIARIES | | ENTERGY CORPORATION AND SUBSIDIARIES |
SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS | | For the Years Ended December 31, 2015, 2014, and 2013 | |
| For the Years Ended December 31, 2016, 2015, and 2014 | | For the Years Ended December 31, 2016, 2015, and 2014 |
(In Thousands) | | Column A | | Column B | | Column C | | Column D | | Column E | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | | | | | | | | | |
| 2016 | | |
| $39,895 |
| |
| $7,505 |
| |
| $35,476 |
| |
| $11,924 |
|
| 2015 | |
| $672 |
| |
| $239 |
| |
| $437 |
| |
| $474 |
| |
| $35,663 |
| |
| $6,926 |
| |
| $2,694 |
| |
| $39,895 |
|
| 2014 | |
| $443 |
| |
| $483 |
| |
| $254 |
| |
| $672 |
| |
| $34,311 |
| |
| $4,573 |
| |
| $3,221 |
| |
| $35,663 |
|
| 2013 | |
| $680 |
| |
| ($237 | ) | |
| $— |
| |
| $443 |
| |
| Notes: | | |
| | |
| | |
| | |
| | |
| | |
| | |
| | |
|
(1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY ARKANSAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2016 | |
| $34,226 |
| |
| $902 |
| |
| $33,917 |
| |
| $1,211 |
|
| 2015 | |
| $32,247 |
| |
| $2,759 |
| |
| $780 |
| |
| $34,226 |
|
| 2014 | |
| $30,113 |
| |
| $2,881 |
| |
| $747 |
| |
| $32,247 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY LOUISIANA, LLC AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2016 | |
| $4,209 |
| |
| $2,942 |
| |
| $874 |
| |
| $6,277 |
|
| 2015 | |
| $1,609 |
| |
| $3,464 |
| |
| $864 |
| |
| $4,209 |
|
| 2014 | |
| $1,874 |
| |
| $842 |
| |
| $1,107 |
| |
| $1,609 |
|
| 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, 2016, 2015, and 2014 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2016 | |
| $718 |
| |
| $259 |
| |
| $428 |
| |
| $549 |
|
| 2015 | |
| $873 |
| |
| $247 |
| |
| $402 |
| |
| $718 |
|
| 2014 | |
| $906 |
| |
| $269 |
| |
| $302 |
| |
| $873 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY NEW ORLEANS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2016 | |
| $268 |
| |
| $2,872 |
| |
| $81 |
| |
| $3,059 |
|
| 2015 | |
| $262 |
| |
| $217 |
| |
| $211 |
| |
| $268 |
|
| 2014 | |
| $974 |
| |
| $99 |
| |
| $811 |
| |
| $262 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
|
| | | | | | | | | | | | | | | | |
| ENTERGY TEXAS, INC. AND SUBSIDIARIES |
| SCHEDULE II - VALUATION AND QUALIFYING ACCOUNTS |
| For the Years Ended December 31, 2016, 2015, and 2014 |
| (In Thousands) |
| Column A | | Column B | | Column C | | Column D | | Column E |
| | | | | | | Other | | |
| | | Balance at | | Additions | | Changes | | Balance |
| Description | | Beginning of Period | | Charged to Income | | Deductions (1) | | at End of Period |
| Allowance for doubtful accounts | | | | | | | | |
| 2016 | |
| $474 |
| |
| $531 |
| |
| $177 |
| |
| $828 |
|
| 2015 | |
| $672 |
| |
| $239 |
| |
| $437 |
| |
| $474 |
|
| 2014 | |
| $443 |
| |
| $483 |
| |
| $254 |
| |
| $672 |
|
| Notes: | | |
| | |
| | |
| | |
|
| (1) Deductions represent write-offs of accounts receivable balances and are reduced by recoveries of amounts previously written off. |
EXHIBIT INDEX
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.
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
Entergy Louisiana
|
| |
| (a) 1 -- | Plan of Merger of Entergy Gulf States Power, LLC and Entergy Gulf States Louisiana, LLC (2.1 to Form 8-K12B filed October 1, 2015 in 1-32718). |
| | |
| (a) 2 -- | Plan of Merger of Entergy Louisiana, LLC and Entergy Louisiana Power, LLC (2.2 to Form 8-K12B filed October 1, 2015 in 1-32718). |
| | |
| (a) 3 -- | Plan of Merger of Entergy Gulf States Power, LLC and Entergy Louisiana Power, LLC (2.3 to Form 8-K12B filed October 1, 2015 in 1-32718). |
(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 in 1-11299). |
| | |
| (a) 2 -- | By-LawsBylaws of Entergy Corporation as amended February 12, 2007,January 27, 2017, and as presently in effect (3(ii)(3.1 to Form 8-K filed February 16, 2007January 30, 2017 in 1-11299). |
System Energy
|
| |
| (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). |
Entergy Arkansas
|
| |
| (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 filed 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 Louisiana
|
| |
| (d) 1 -- | Certificate of Formation of Entergy Louisiana Power, LLC (including Certificate of Amendment to Certificate of Formation to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.3 to Form 8-K12B filed October 1, 2015 in 1-32718). |
| | |
| (d) 2 -- | Company Agreement of Entergy Louisiana Power, LLC (including First Amendment to Company Agreement to change the company name to Entergy Louisiana, LLC) effective July 7, 2015 (3.4 to Form 8-K12B filed October 1, 2015 in 1-32718). |
Entergy Mississippi
|
| |
| (e) 1 -- | Second Amended and Restated Articles of Incorporation of Entergy Mississippi, effective July 21, 2009 (99.1 to Form 8-K filed July 27, 2009 in 1-31508). |
| | |
| (e) 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). |
Entergy New Orleans
|
| |
| (f) 1 -- | Amended and Restated Articles of Incorporation of Entergy New Orleans, effective May 8, 2007 (3(a) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
| | |
| (f) 2 -- | Amended By-Laws of Entergy New Orleans effective May 8, 2007, and as presently in effect (3(b) to Form 10-Q for the quarter ended March 31, 2007 in 0-5807). |
Entergy Texas
|
| |
| (g) 1 -- | Certificate of Formation of Entergy Texas, effective December 31, 2007 (3(i) to Form 10 filed March 14, 2008 in 000-53134). |
| | |
| (g) 2 -- | Bylaws of Entergy Texas effective December 31, 2007 (3(ii) to Form 10 filed March 14, 2008 in 000-53134). |
(4)Instruments Defining Rights of Security Holders, Including Indentures
Entergy Corporation
|
| |
| (a) 1 -- | See (4)(b) through (4)(g) below for instruments defining the rights of security holders of long-term debt of System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and Entergy Texas. |
| | |
| (a) 2 -- | Indenture (For Unsecured Debt Securities), dated as of September 1, 2010, between Entergy Corporation and Wells Fargo Bank, National Association (4.01 to Form 8-K filed September 16, 2010 in 1-11299). |
| | |
| (a) 3 -- | Officer’s Certificate for Entergy Corporation relating to 5.125% Senior Notes due September 15, 2020 (4.02(b) to Form 8-K filed September 16, 2010 in 1-11299). |
| | |
| (a) 4 -- | Officer’s Certificate for Entergy Corporation relating to 4.70% Senior Notes due January 15, 2017 (4.02 to Form 8-K filed January 13, 2012 in 1-11299). |
| |
(a) 5 -- | Officer’s Certificate for Entergy Corporation relating to 4.50% Senior Note due December 16, 2028 (4(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
|
| |
| (a) 5 -- | Officer’s Certificate for Entergy Corporation relating to 2.95% Senior Notes due September 1, 2026 (4.02 to Form 8-K filed August 19, 2016 in 1-11299). |
| | |
| (a) 6 -- | Officer’s Certificate for Entergy Corporation relating to 4.0% Senior Note due July 15, 2022 (4.02 to Form 8-K dated July 1, 2015 in 1-11299). |
| | |
| (a) 7 -- | Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(g) to Form 10-Q for the quarter ended September 30, 2015 in 1-11299). |
| | |
| (a) 8 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(h) to Form 10-Q for the quarter ended September 30, 2015 in 1-11299). |
| |
| (a) 9 -- | Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299). |
| |
| (a) 10 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Corporation, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(m) to Form 10-Q for the quarter ended September 30, 2016 in 1-11299). |
System Energy
|
| |
| (b) 1 -- | Mortgage and Deed of Trust, dated as of June 15, 1977, as amended and restated by twenty-fourthe following 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 filed October 4, 2002 in 70-9753 (Twenty-second); 4(b) to Form 10-Q for the quarter ended September 30, 2007 in 1-9067 (Twenty-third); and 4.42Indenture: (4.42 to Form 8-K dated September 25, 2012 in 1-9067 (Twenty-fourth)). |
| | |
| (b) 2 -- | Facility Lease No. 1,Loan Agreement, dated as of December 1, 1988,October 15, 1998, between Meridian Trust Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees, and System Energy (B-2(c)(1)and Mississippi Business Finance Corporation (B-6(b) to Rule 24 Certificate dated January 9, 1989November 12, 1998 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)70-8511). |
| | |
| (b) 3 -- | FacilityFuel Lease, No. 2, dated as of December 1, 1988February 24, 1989, between Meridian TrustRiver Fuel Funding Company and Stephen M. Carta (Steven Kaba, successor), as Owner Trustees,#3, Inc. and System Energy (B-2(c)(2)(B-1(b) to Rule 24 Certificate dated January 9,March 3, 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)70-7604). |
Entergy Arkansas
|
| |
| (c) 1 -- | Mortgage and Deed of Trust, dated as of October 1, 1944, as amended by seventy-eightthe following Supplemental IndenturesIndentures: (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, 199531,1995 (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, 2006 in 1-10764 (Sixty-sixth); 4(b) to Form 10-Q for the quarter ended June 30, 2008 in 1-10764 (Sixty-seventh); 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); 4(e) to Form 8-K dated January 9, 2013 in 1-10764 (Seventy-second); 4.06 to Form 8-K dated May 30, 2013 in 1-10764 (Seventy-third); 4.06 to Form 8-K dated June 4, 2013 in 1-10764 (Seventy-fourth); 4.02 to Form 8-K dated July 26, 2013 in 1-10764 (Seventy-fifth); 4.05 to Form 8-K dated March 14, 2014 in 1-10764 (Seventy-sixth); 4.05 to Form 8-K dated December 9, 2014 in 1-10764 (Seventy-seventh); and 4.05 to Form 8-K dated January 8, 2016 in 1-10764 (Seventy-eighth); and 4.05 to Form 8-K dated August 16, 2016 in 1-10764 (Seventy-ninth)). |
|
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| (c) 2 -- | Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(i) to Form 10-Q for the quarter ended September 30, 2015 in 1-10764). |
| | |
| (c) 3 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(j) to Form 10-Q for the quarter ended September 30, 2015 in 1-10764). |
| |
| (c) 4 -- | Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(n) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764). |
| |
| (c) 5 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Arkansas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(o) to Form 10-Q for the quarter ended September 30, 2016 in 1-10764). |
| |
| (c) 6 -- | 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) 7 -- | Loan Agreement, dated as of January 1, 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764). |
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| (c) 8 -- | Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764). |
Entergy Louisiana
|
| |
| (d) 1 -- | Mortgage and Deed of Trust, dated as of April 1, 1944, as amended by eighty-twothe following Supplemental IndenturesIndentures: (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); 4.08 to Form 8-K dated December 4, 2012 in 1-32718 (Seventy-sixth); 4.08 to Form 8-K dated May 21, 2013 in 1-32718 (Seventy-seventh); 4.08 to Form 8-K dated August 23, 2013 in 1-32718 (Seventy-eighth); 4.08 to Form 8-K dated June 24, 2014 in 1-32718 (Seventy-ninth); 4.08 to Form 8-K dated July 1, 2014 in 1-32718 (Eightieth); 4.08 to Form 8-K dated November 21, 2014 (Eighty-first); and 4.1 to Form 8-K12B dated October 1, 2015 (Eighty-second)). |
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(d) 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; 4(g) 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, 1997March 18, 2016 in 1-8474). |
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(d) 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 (attached1-32718 (Eighty-third); 4.33 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, 1997March 24, 2016 in 1-8474)1-32718 (Eighty-fourth); 4(k) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Eighty-fifth); 4.33 to Form 8-K dated August 17, 2016 in 1-32718 (Eighty-sixth); and 4.33 to Form 8-K dated October 4, 2016 in 1-32718 (Eighty-seventh)). |
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(d) 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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(d) 52 -- | Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana LLC [Old Entergy Louisiana] and Entergy Gulf States Louisiana, L.L.C., as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4.4 to Form 8-K12B filed October 1, 2015 in 1-32718). |
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(d) 63 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana LLC [Old Entergy Louisiana] and Entergy Gulf States Louisiana, L.L.C., as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4.5 to Form 8-K12B filed October 1, 2015 in 1-32718). |
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(d) 74 -- | Borrower Assumption Agreement dated as of October 1, 2015 of Entergy Louisiana LLC [New Entergy Louisiana] under Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana LLC [Old Entergy Louisiana] and Entergy Gulf States Louisiana, L.L.C., as the Borrowers, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto, as amended (4.6 to Form 8-K12B filed October 1, 2015 in 1-32718). |
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| (d) 5 -- | Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(p) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718). |
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| (d) 6 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Louisiana, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(q) to Form 10-Q for the quarter ended September 30, 2016 in 1-32718). |
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| (d) 7 -- | 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). |
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| (d) 8 -- | 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). |
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| (d) 9 -- | Loan Agreement, dated as of March 1, 2016, between the Louisiana Public Facilities Authority and Entergy Louisiana relating to Refunding Revenue Bonds (Entergy Louisiana, LLC Project) Series 2016A (4(b) to Form 8-K filed March 18, 2016 in 1-32718). |
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| (d) 10 -- | Loan Agreement, dated as of March 1, 2016, between Louisiana Public Facilities Authority and Entergy Louisiana relating to Refunding Revenue Bonds (Entergy Louisiana, LLC Project) Series 2016B (4(d) to Form 8-K filed March 18, 2016 in 1-32718). |
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| (d) 11 -- | Indenture of Mortgage, dated September 1, 1926, as amended by certainthe following Supplemental Indentures (B-a-I-1 in Registration No. 2-2449 (Mortgage); 7-A-9Indentures: (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); 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); 4(f) to Form 8-K filed October 12, 2010 in 0-20371 (Eightieth); 4.07 to Form 8-K dated July 1, 2014 in 0-20371 (Eighty-first); 4.2 to Form 8-K12B dated October 1, 2015 in 1-32718 (Eighty-second); and 4.3 to Form 8-K12B dated October 1, 2015 in 1-32718 (Eighty-third); 4.42 to Form 8-K dated March 24, 2016 in 1-32718 (Eighty-fourth); 4.42 to Form 8-K dated May 19, 2016 in 1-32718 (Eighty-fifth); 4.42 to Form 8-K dated August 17, 2016 in 1-32718 (Eighty-sixth); and 4.42 to Form 8-K dated October 4, 2016 in 1-32718 (Eighty-seventh)). |
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(d) 9 -- | 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) 1012 -- | 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) 13 -- | Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015, as amended by the following Supplemental Indentures: (4.38 in Registration No. 333-190911-07 (Mortgage); 4(f) to Form 8-K filed March 18, 2016 in 1-32718 (First); 4.40 to Form 8-K filed March 24, 2016 in 1-32718 (Second); 4(g) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Third); 4(h) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718 (Fourth); 4.40 to Form 8-K filed May 19, 2016 in 1-32718 (Fifth); 4.40 to Form 8-K filed August 17, 2016 in 1-32718 (Sixth); and 4.41 to Form 8-K filed October 4, 2016 in 1-32718 (Seventh)). |
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| (d) 14 -- | Officer’s Certificate No. 1-B-1, dated March 18, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(e) to Form 8-K filed March 19, 2016 in 1-32718). |
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| (d) 15 -- | Officer’s Certificate No. 2-B-2, dated March 17, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed March 24, 2016 in 1-32718). |
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| (d) 16 -- | Officer’s Certificate No. 3-B-3, dated March 28, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4(d) to Form 10-Q for the quarter ended March 31, 2016 in 1-32718). |
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| (d) 17 -- | Officer’s Certificate No. 4-B-4, dated May 16, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed May 19, 2016 in 1-32718). |
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| (d) 18 -- | Officer’s Certificate No. 6-B-5, dated August 1, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.39 to Form 8-K filed August 17, 2016 in 1-32718). |
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| (d) 19 -- | Officer’s Certificate No. 7-B-6, dated September 15, 2016, supplemental to Mortgage and Deed of Trust of Entergy Louisiana, dated as of November 1, 2015 (4.40 to Form 8-K filed October 4, 2016 in 1-32718). |
Entergy Mississippi
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| (e) 1 -- | Mortgage and Deed of Trust, dated as of February 1, 1988, as amended by thirty-onethe following Supplemental IndenturesIndentures: (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); 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); 4.38 to Form 8-K dated December 11, 2012 in 1-31508 (Thirtieth); and 4.05 to Form 8-K dated March 21, 2014 in 1-31508 (Thirty-first); 4.05 to Form 8-K dated May 13, 2016 in 1-31508 (Thirty-second); and 4.16 to Form 8-K dated September 15, 2016 in 1-31508 (Thirty-third)). |
Entergy New Orleans
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| (f) 1 -- | Mortgage and Deed of Trust, dated as of May 1, 1987, as amended by seventeenthe following Supplemental IndenturesIndentures: (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); 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); 4.02 to Form 8-K dated November 29, 2012 in 0-5807 (Sixteenth); and 4.02 to Form 8-K dated June 21, 2013 in 0-5807 (Seventeenth); 4(m) to Form 10-Q for the quarter ended March 31, 2016 in 0-5807 (Eighteenth); 4.02 to Form 8-K dated March 22, 2016 in 0-5807 (Nineteenth); and 4.02 to Form 8-K dated May 24, 2016 in 0-5807 (Twentieth)). |
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*(f) 2 -- | Amended and Restated Credit Agreement ($25,000,000), dated as of November 20, 2015, among Entergy New Orleans, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent.Agent (4(f)2 to Form 10-K for the year ended December 31, 2015 in 0-5807). |
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| (f) 3 -- | Amendment to Amended and Restated Credit Agreement, dated as of June 30, 2016, among Entergy New Orleans, as the Borrower, the banks and other financial institutions party thereto as Lenders, and Bank of America, N.A., as Administrative Agent (4(f) to Form 10-Q for the quarter ended June 30, 2016 in 0-5807). |
Entergy Texas
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| (g) 1 -- | 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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| (g) 2 -- | Officer’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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| (g) 3 -- | Officer’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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| (g) 4 -- | 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). |
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| (g) 5 -- | Officer’s Certificate No. 7-B-5 dated May 13, 2014, 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 May 16, 2014 in 1-34360). |
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| (g) 6 -- | Officer’s Certificate No. 8-B-6 dated May 18, 2015, 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 May 21, 2015 in 1-34360). |
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| (g) 7 -- | Officer’s Certificate No. 9-B-7 dated March 8, 2016, supplemental to Indenture, Deed of Trust and Security Agreement dated as of October 1, 2008, between Entergy Texas and The Bank of New York Mellon, as trustee (4.40 to Form 8-K dated March 11, 2016 in 1-34360). |
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| (g) 8 -- | Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(k) to Form 10-Q for the quarter ended September 30, 2015 in 1-34360). |
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(g) 89 -- | Amendment dated as of August 28, 2015, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, Inc., as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(l) to Form 10-Q for the quarter ended September 30, 2015 in 1-34360). |
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| (g) 10 -- | Extension Agreement, dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(r) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360). |
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| (g) 11 -- | Amendment dated as of August 8, 2016, to Amended and Restated Credit Agreement dated as of August 14, 2015, among Entergy Texas, as the Borrower, the banks and other financial institutions party thereto as Lenders, Citibank, N.A., as Administrative Agent and as an LC Issuing Bank, and the other LC Issuing Banks party thereto (4(s) to Form 10-Q for the quarter ended September 30, 2016 in 1-34360). |
(10) Material Contracts
Entergy Corporation
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| +(a) 1 -- | Agreement, dated April 23, 1982, among certain System companies, relating2007 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 System PlanningEntergy Corporation’s Definitive Proxy Statement filed on March 24, 2006 in 1-11299). |
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| +(a) 2 -- | First Amendment of the 2007 Equity Ownership and DevelopmentLong Term Cash Incentive Plan of Entergy Corporation and Intra-System TransactionsSubsidiaries effective October 26, 2006 (10(a)150 to Form 10-K for the year ended December 31, 19822010 in 1-3517)1-11299). |
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+(a) 23 -- | Second AmendedAmendment of the 2007 Equity Ownership and RestatedLong 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) 4 -- | 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) 5 -- | 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) 6 -- | 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Annex C to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299). |
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| +(a) 7 -- | Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 8 -- | First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 9 -- | 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) 10 -- | Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
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| +(a) 11 -- | Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
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| +(a) 12 -- | Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 13 -- | First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 14 -- | 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) 15 -- | 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) 16 -- | Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 17 -- | 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) 18 -- | 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) 19 -- | System Agency Agreement, datedExecutive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 20082009 (10(a)277 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
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| +(a) 20 -- | First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
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| +(a) 21 -- | 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). |
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| +(a) 22 -- | 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). |
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| +(a) 23 -- | 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). |
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| +(a) 24 -- | 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). |
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| +(a) 25 -- | Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 26 -- | First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 27 -- | 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). |
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| +(a) 28 -- | Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
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| +(a) 29 -- | Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
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| +(a) 30 -- | Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
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| +(a) 31 -- | 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). |
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| +(a) 32 -- | System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 33 -- | First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
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| +(a) 34 -- | 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). |
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| +(a) 35 -- | Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 26, 2012 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
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| +(a) 36 -- | Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the year ended June 30, 2013 in 1-11299). |
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| +(a) 37 -- | Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the year ended September 30, 2014 in 1-11299). |
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| +(a) 38 -- | 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) 39 -- | 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) 40 -- | 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) 41 -- | 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) 42 -- | 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) 43 -- | Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
| +(a) 44 -- | 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) 45 -- | Entergy Corporation Non-Employee Director Stock Program Established under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(c) to Form 10-Q for the quarter ended June 30, 2015 in 1-11299). |
| |
| +(a) 46 -- | 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) 347 -- | Middle South Utilities System Agency CoordinationForm of Stock Option Grant Agreement. |
| |
| *+(a) 48 -- | Form of Long Term Incentive Program Performance Unit Agreement. |
| |
| *+(a) 49 -- | Form of Restricted Stock Grant Agreement. |
| |
| +(a) 50 -- | Restricted Units Agreement dated December 11, 1970 (5(a)3between Roderick K. West and Entergy Corporation (10(a) to Form 10-Q for the quarter ended June 30, 2013 in 2-41080)1-11299). |
| | |
+(a) 451 -- | ServiceRestricted Stock Unit Agreement withbetween Andrew S. Marsh and Entergy Services, dated as of April 1, 1963 (5(a)5 in 2-41080). |
| |
(a) 5 -- | Amendment, dated April 27, 1984, to Service Agreement with Entergy ServicesCorporation (10(a)7102 to Form 10-K for the year ended December 31, 19842015 in 1-3517)1-11299). |
| | |
+(a) 652 -- | Amendment, datedExecutive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2000,2016 (Appendix B to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299). |
| |
| +(a) 53 -- | Service Agreement withRecognition Program for Non-Employee Outside Directors of Entergy Services (10(a)12Corporation and Subsidiaries, as amended and restated effective June 1, 2015 (10(d) to Form 10-K10-Q for the yearquarter ended December 31, 2001June 30, 2015 in 1-11299). |
| | |
|
| |
*+(a) 754 -- | Amendment, dated December 19, 2013, to ServiceRestricted Stock Units Agreement withby and between A. Christopher Bakken, III and Entergy Services (10(a)7 to Form 10-K for the year ended December 31, 2013 in 1-11299).Corporation effective April 6, 2016. |
| | |
*+(a) 855 -- | Offer Letter, dated January 28, 2016, by and between A. Christopher Bakken, III and Entergy Services, Inc. |
System Energy
|
| |
| (b) 1 -- | 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). |
| | |
(a) 9(b) 2 -- | First Amendment to Availability Agreement, dated as of June 30, 1977 (B to Rule 24 Certificate dated June 24, 1977 in 70-5399). |
| | |
(a) 10(b) 3 -- | Second Amendment to Availability Agreement, dated as of June 15, 1981 (E to Rule 24 Certificate dated July 1, 1981 in 70-6592). |
| | |
(a) 11(b) 4 -- | 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). |
| | |
(a) 12(b) 5 -- | Fourth Amendment to Availability Agreement, dated as of June 1, 1989 (A to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
| | |
(a) 13(b) 6 -- | Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 1, 2012, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (10(a)15 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
| | |
(a) 14(b) 7 -- | Amendment to the Thirty-seventh Assignment of Availability Agreement, Consent and Agreement, dated as of September 18, 2015, among System Energy, Entergy Arkansas, Entergy Louisiana, Entergy Mississippi, Entergy New Orleans, and The Bank of New York Mellon, as successor trustee (4.25 to Form S-3 dated October 2, 2015). |
| | |
(a) 15(b) 8 -- | 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). |
| | |
(a) 16(b) 9 -- | First Amendment to Capital Funds Agreement, dated as of June 1, 1989 (B to Rule 24 Certificate dated June 8, 1989 in 70-5399). |
| | |
(a) 17(b) 10 -- | Thirty-seventh Supplementary Capital Funds Agreement and Assignment, dated as of September 1, 2012, among Entergy Corporation, System Energy, and The Bank of New York Mellon, as successor trustee (10(a)19 to Form 10-K for the year ended December 31, 2012 in 1-11299). |
| | |
(a) 18 -- | 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). |
| |
(a) 19 -- | 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). |
| |
(a) 20 -- | 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). |
| |
(a) 21 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| |
(a) 22 -- | 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). |
|
| |
| |
(a) 23 -- | Operating Agreement dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
| |
(a) 24 -- | 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). |
| |
(a) 25 -- | 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). |
| |
(a) 26 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
| |
(a) 27 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
| |
(a) 28 -- | 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). |
| |
(a) 29 -- | 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). |
| |
(a) 30 -- | 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). |
| |
(a) 31 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(a) 32 -- | 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). |
| |
(a) 33 -- | 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). |
| |
(a) 34 -- | 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). |
| |
(a) 35 -- | 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). |
| |
(a) 36 -- | 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). |
| |
(a) 37 -- | 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). |
| |
(a) 38 -- | Sixth Amendment dated October(b) 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). |
| |
(a) 39 -- | 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). |
|
| |
| |
(a) 40 -- | 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). |
| |
(a) 41 -- | 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). |
| |
(a) 42 -- | 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). |
| |
(a) 43 -- | 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). |
| |
+(a) 44 -- | 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 filed on March 24, 2006 in 1-11299). |
| |
+(a) 45 -- | 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). |
| |
+(a) 46 -- | 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). |
| |
+(a) 47 -- | 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). |
| |
+(a) 48 -- | 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). |
| |
+(a) 49 -- | 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) 50 -- | 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). |
| |
+(a) 51 -- | 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). |
| |
+(a) 52 -- | 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). |
| |
+(a) 53 -- | 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (Annex C to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299). |
| |
+(a) 54 -- | Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)57 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 55 -- | First Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)58 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 56 -- | 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). |
| |
|
| |
+(a) 57 -- | Third Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(b) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 58 -- | Fourth Amendment of the Supplemental Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(c) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 59 -- | Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)59 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 60 -- | First Amendment of the Defined Contribution Restoration Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)60 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 61 -- | 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). |
| |
+(a) 62 -- | 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). |
| |
+(a) 63 -- | Executive Deferred Compensation Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)62 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 64 -- | 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). |
| |
+(a) 65 -- | 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). |
| |
+(a) 66 -- | System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective as of January 1, 2009 (10(a)77 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
+(a) 67-- | First Amendment of the System Executive Continuity Plan of Entergy Corporation and Subsidiaries, effective January 1, 2010 (10(a)78 to Form 10-K for the year ended December 31, 2009 in 1-11299). |
| |
+(a) 68 -- | 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) 69 -- | 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) 70 -- | 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) 71 -- | 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) 72 -- | Pension Equalization Plan of Entergy Corporation and Subsidiaries, as amended and restated effective January 1, 2009 (10(a)74 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 73 -- | First Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)75 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 74 -- | 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) 75 -- | Third Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective June 19, 2013 (10(b) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
+(a) 76 -- | Fourth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(c) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
+(a) 77 -- | Fifth Amendment of the Pension Equalization Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(a) to Form 10-Q for the quarter ended September 30, 2014 in 1-11299). |
| |
+(a) 80 -- | 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) 81 -- | System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 1, 2009 (10(a)78 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 82 -- | First Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective December 30, 2010 (10(a)79 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 83-- | 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) 84 -- | Third Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective January 26, 2012 (10(a)81 to Form 10-K for the year ended December 31, 2013 in 1-11299). |
| |
+(a) 85 -- | Fourth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 25, 2013 (10(d) to Form 10-Q for the year ended June 30, 2013 in 1-11299). |
| |
+(a) 86 -- | Fifth Amendment of the System Executive Retirement Plan of Entergy Corporation and Subsidiaries, effective July 1, 2014 (10(d) to Form 10-Q for the year ended September 30, 2014 in 1-11299). |
| |
+(a) 87 -- | 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) 88 -- | 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) 89 -- | 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) 90 -- | 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) 91 -- | 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) 92 -- | Amendment to Retention Agreement effective December 30, 2010 between Leo P. Denault and Entergy Corporation (10(a)95 to Form 10-K for the year ended December 31, 2010 in 1-11299). |
| |
+(a) 93 -- | 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) 94 -- | Entergy Corporation Non-Employee Director Stock Program Established under the 2015 Equity Ownership Plan of Entergy Corporation and Subsidiaries (10(c) to Form 10-Q for the quarter ended June 30, 2015 in 1-11299). |
| |
|
| |
+(a) 95 -- | 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)96-- | Form of Stock Option Grant Agreement. |
| |
*+(a)97-- | Form of Long Term Incentive Program Performance Unit Agreement. |
| |
*+(a)98-- | Form of Restricted Stock Grant Agreement. |
| |
(a) 99 -- | Employee Matters Agreement, dated as of December 4, 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)100- | Retention Agreement effective February 1, 2013 between William M. Mohl and Entergy Corporation (10(a)105 to Form 10-K for the year ended December 31, 2014 in 1-11299). |
| |
+(a)101 -- | Restricted Units Agreement between Roderick K. West and Entergy Corporation (10(a) to Form 10-Q for the quarter ended June 30, 2013 in 1-11299). |
| |
*+(a)102- | Restricted Stock Unit Agreement between Andrew S. Marsh and Entergy Corporation. |
| |
+(a) 103 -- | Executive Annual Incentive Plan of Entergy Corporation and Subsidiaries as amended and restated effective January 1, 2016 (Appendix B to 2015 Entergy Corporation’s Definitive Proxy Statement filed on March 20, 2015 in 1-11299). |
| |
+(a) 104 -- | Service Recognition Program for Non-Employee Outside Directors of Entergy Corporation and Subsidiaries, as amended and restated effective June 1, 2015 (10(d) to Form 10-Q for the quarter ended June 30, 2015 in 1-11299). |
System Energy
|
| |
(b) 1 through |
(b) 13 -- See 10(a)8 through 10(a)20 above. |
|
(b) 14 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| |
(b) 15 -- | 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) 16 -- | Operating Agreement, dated as of May 1, 1980, between System Energy and SMEPA (B(2)(a) in 70-6337). |
| |
(b) 17 -- | 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) 18 -- | 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) 19 -- | 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) 12 -- | Lease Supplement No. 4, dated as of January 15, 2014, to Facility Lease No. 1. |
| |
|
| |
(b) 2013 -- | 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) 2114 -- | Assignment, Assumption and Further AgreementLease Supplement No. 1,4, dated as of December 1, 1988, among System Energy, Meridian Trust Company and Stephen M. Carta, and SMEPA (B-7(c)(1)May 28, 2014, to Rule 24 Certificate dated January 9, 1989 in 70-7561).Facility Lease No. 2. |
| | |
(b) 22 -- | 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) 23 -- | Substitute Power Agreement, dated as of May 1, 1980, among Entergy Mississippi, System Energy and SMEPA (B(3)(a) in 70-6337). |
| |
(b) 24 -- | Grand Gulf Unit No. 2 Supplementary Agreement, dated as of February 7, 1986, between System Energy and SMEPA (10(aaa) in 33-4033). |
| |
(b) 25 -- | 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) 26 -- | 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) 27 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(b) 28 -- | 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) 29 -- | System Energy’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) 30 -- | 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) 31 -- | 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) 32 -- | 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) 33 -- | 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) 34 -- | 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) 35 -- | 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) 36 -- | 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) 37 -- | 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) 38 -- | 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 1-9067). |
| |
(b) 39 -- | 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) 40 -- | 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) 41 -- | 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) 42 -- | Amendment, dated December 19, 2013, to Service Agreement with Entergy Services (10(b)44 to Form 10-K for the year ended December 31, 2013 in 1-9067). |
| |
(b) 43 -- | 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) 44 -- | 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) 45 -- | 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) 46 -- | 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). |
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(b) 47 -- | 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) 48 -- | 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). |
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(b) 49 -- | Third Amendment and Consent, dated as of May 14, 2009, to Letter of Credit and Reimbursement Agreement (10(b)69 to Form 10-K for the year ended December 31, 2009 in 1-9067). |
| |
(b) 50 -- | 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) 51 -- | Fifth Amendment and Consent, dated as of November 15, 2012, to Letter of Credit and Reimbursement Agreement (10(b)55 to Form 10-K for the year ended December 31, 2012 in 1-9067). |
Entergy Arkansas
|
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(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). |
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|
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(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 December 19, 2013, to Service Agreement, with Entergy Services (includes Service Agreement for Generation Planning and Operational Support Services, and Service Agreement for Transmission Planning and Reliability Support Services, but excludes Amended and Restated Service Agreement for Administrative and General Support Services) (10(c)5 to Form 10-K for the year ended December 31, 2013 in 1-10764). |
| |
*(c) 6 -- | Amendment, dated November 8, 2015, to Service Agreement, with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services). |
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(c) 7 through |
(c) 13 -- See 10(a)8 through 10(a)14 above. |
|
(c) 14 -- | Agreement, dated August 20, 1954, between Entergy Arkansas and the United States of America (SPA)(13(h) in 2-11467). |
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(c) 15 -- | Amendment, dated April 19, 1955, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)2 in 2-41080). |
| |
(c) 16 -- | Amendment, dated January 3, 1964, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)3 in 2-41080). |
| |
(c) 17 -- | Amendment, dated September 5, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)4 in 2-41080). |
| |
(c) 18 -- | Amendment, dated November 19, 1970, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)5 in 2-41080). |
| |
(c) 19 -- | Amendment, dated July 18, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)6 in 2-41080). |
| |
(c) 20 -- | Amendment, dated December 27, 1961, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)7 in 2-41080). |
| |
(c) 21 -- | Amendment, dated January 25, 1968, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)8 in 2-41080). |
| |
(c) 22 -- | Amendment, dated October 14, 1971, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)9 in 2-43175). |
| |
(c) 23 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated August 20, 1954 (5(d)10 in 2-60233). |
| |
(c) 24 -- | Agreement, dated May 14, 1971, between Entergy Arkansas and the United States of America (SPA) (5(e) in 2-41080). |
| |
(c) 25 -- | Amendment, dated January 10, 1977, to the United States of America (SPA) Contract, dated May 14, 1971 (5(e)1 in 2-60233). |
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|
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(c) 26 -- | 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) 27 -- | 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) 28 -- | 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) 29 -- | 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) 30 -- | Agreement, dated June 29, 1979, between Entergy Arkansas and City of Conway, Arkansas (5(r)3 in 2-66235). |
| |
(c) 31 -- | 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) 32 -- | 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) 33 -- | 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) 34 -- | 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) 35 -- | 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) 36 -- | Amendment, dated December 28, 1979, to the Independence Steam Electric Station Ownership Agreement (5(r)7(a) in 2-66235). |
| |
(c) 37 -- | 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) 38 -- | Owner’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) 39 -- | 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) 40 -- | 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) 41 -- | 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) 42 -- | 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). |
|
| |
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(c) 43 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| | |
(c) 44*(b) 16 -- | 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) 45 -- | First Amendment to Unit Power Sales Agreement, dated as of June 28, 1984, betweenamong 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) 46 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(c) 47 -- | 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) 48 -- | 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) 49 -- | 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) 50 -- | 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) 51 -- | 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) 52 -- | 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) 53 -- | 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 1-10764). |
| |
(c) 54 -- | 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) 55 -- | 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) 56 -- | 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) 57 -- | 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) 58 -- | Guaranty Agreement between Entergy Corporation10, 1982, as amended and Entergy Arkansas, dated as of September 20, 1990 (B-1(a) to Rule 24 Certificate dated September 27, 1990 in 70-7757). |
| revised. |
|
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(c) 59 -- | 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). |
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(c) 60 -- | 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) 61 -- | 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) 62 -- | 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) 63 -- | 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) 64 -- | Loan Agreement, dated as of January 1 2013, between Jefferson County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(b) to Form 8-K filed January 9, 2013 in 1-10764). |
| |
(c) 65 -- | Loan Agreement, dated as of January 1, 2013, between Independence County, Arkansas and Entergy Arkansas relating to Revenue Bonds (Entergy Arkansas, Inc. Project) Series 2013 (4(d) to Form 8-K filed January 9, 2013 in 1-10764). |
Entergy Louisiana
|
| |
(d) 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). |
| |
(d) 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). |
| |
(d) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
| |
*(d) 4 -- | Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services), dated as of October 1, 2015. |
| |
*(d) 5 -- | Amendment, dated November 8, 2015, to Service Agreement, with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services). |
| |
(d) 6 through |
(d) 12 -- See 10(a)8 through 10(a)14 above. |
| |
(d) 13 -- | 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). |
| |
(d) 14 -- | Reallocation Agreement, dated as of July 28, 1981, among System Energy and certain other System companies (B-1(a) in 70-6624). |
| |
(d) 15 -- | 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). |
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|
| |
(d) 16 -- | 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). |
| |
(d) 17 -- | 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). |
| |
(d) 18 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
| |
(d) 19 -- | 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). |
| |
(d) 20 -- | 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). |
| |
(d) 21 -- | 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). |
| |
(d) 22 -- | Second Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of July 22, 2010 (10(a) to Form 10-Q for the quarter ended June 30, 2010). |
| |
(d) 23 -- | Third Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of August 6, 2014 (10(a) to Form 10-Q for the quarter ended June 30, 2014). |
| |
(d) 24 -- | Fourth Amended and Restated Limited Liability Company Agreement of Entergy Holdings Company LLC dated as of September 19, 2015 (10(b) to Form 10-Q for the quarter ended September 30, 2015). |
| |
(d) 25 -- | 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) 26 -- | 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) 27 -- | 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). |
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(d) 28 -- | 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 1-32718). |
| |
(d) 29 -- | 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). |
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(d) 30 -- | 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). |
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|
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(d) 31 -- | 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) 32 -- | 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) 33 -- | 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) 34 -- | 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) 35 -- | 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). |
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(d) 36 -- | 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) 37 -- | 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). |
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+(d) 38 -- | 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). |
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+(d) 39 -- | 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) 40 -- | 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) 41 -- | 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). |
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+(d) 42 -- | 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). |
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|
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(d) 43 -- | 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). |
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(d) 44 -- | Trust and Investment Management Agreement between Entergy Gulf States, Inc. and Morgan Guaranty and Trust Company of New York (the “Decommissioning Trust 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). |
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(d) 45 -- | 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). |
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(d) 46 -- | 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). |
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(d) 47 -- | 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). |
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(d) 48 -- | 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). |
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(d) 49 -- | 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). |
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+(d) 50 -- | 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). |
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+(d) 51 -- | 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). |
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+(d) 52 -- | Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
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(d) 53 -- | 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). |
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(d) 54 -- | 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). |
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(d) 55 -- | 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). |
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(d) 56 -- | 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). |
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|
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(d) 57 -- | 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). |
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(d) 58 -- | Asset Purchase Agreement, dated as of December 8, 2014, by and among Union Power Partners, L.P., Entegra TC LLC, Entergy Arkansas, Entergy Gulf States Louisiana, and Entergy Texas (10.1 to Form 8-K filed December 12, 2014 in 0-20371). |
Entergy Mississippi
|
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(e) 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). |
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(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 1-31508). |
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(e) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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(e) 4 -- | Service Agreement with Entergy Services, dated as of April 1, 1963 (D in 37-63). |
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*(e) 5 -- | Amendment, dated November 8, 2015, to Service Agreement with Entergy Services (includes Service Agreement for Generation Planning and Operational Support Services and Service Agreement for Transmission Planning and Reliability Support Services). |
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*(e) 6 -- | Amendment, dated November 8, 2015, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services). |
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(e) 7 through |
(e) 13 -- See 10(a)8 through 10(a)14 above. |
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(e) 14 -- | 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). |
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(e) 15 -- | 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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(e) 16 -- | 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). |
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(e) 17 -- | 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). |
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(e) 18 -- | 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). |
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(e) 19 -- | 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). |
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(e) 20 -- | 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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+(e) 21 -- | Post-Retirement Plan (10(d)24 to Form 10-K for the year ended December 31, 1983 in 0-320). |
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|
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(e) 22 -- | 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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(e) 23 -- | 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). |
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(e) 24 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(e) 25 -- | 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). |
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(e) 26 -- | 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). |
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(e) 27 -- | 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). |
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(e) 28 -- | 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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(e) 29 -- | 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). |
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(e) 30 -- | 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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(e) 31 -- | 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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(e) 32 -- | 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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(e) 33 -- | 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 1-31508). |
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(e) 34 -- | 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 1-31508). |
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(e) 35 -- | 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). |
|
| |
(f) 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). |
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(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 0-5807). |
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(f) 3 -- | Middle South Utilities System Agency Coordination Agreement, dated December 11, 1970 (5(a)3 in 2-41080). |
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|
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(f) 4 -- | Service Agreement with Entergy Services dated as of April 1, 1963 (5(a)5 in 2-42523). |
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*(f) 5 -- | Amendment, dated November 8, 2015, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services). |
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(f) 6 through |
(f) 12 -- See 10(a)8 through 10(a)14 above. |
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(f) 13 -- | 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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(f) 14 -- | 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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(f) 15 -- | 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). |
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(f) 16 -- | Revised Unit Power Sales Agreement (10(ss) in 33-4033). |
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(f) 17 -- | 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). |
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(f) 18 -- | 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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(f) 19 -- | 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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(f) 20 -- | 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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(f) 21 -- | 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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(f) 22 -- | 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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(f) 23 -- | 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 0-5807). |
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(f) 24 -- | 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). |
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(f) 25 -- | 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). |
Entergy Texas
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(g) 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). |
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(g) 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). |
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(g) 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). |
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(g) 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). |
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(g) 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). |
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(g) 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). |
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(g) 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). |
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+(g) 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). |
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+(g) 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). |
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+(g) 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). |
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+(g) 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). |
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+(g) 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). |
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|
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(g) 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). |
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+(g) 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). |
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+(g) 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). |
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+(g) 16 -- | Gulf States Utilities Board of Directors’ Retirement Plan, dated February 15, 1991 (10-8 to Form 10-K for the year ended December 31, 1990 in 1-27031). |
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(g) 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). |
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(g) 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). |
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(g) 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 1-34360). |
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(g) 20 -- | 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 1-34360). |
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(g) 21 -- | 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). |
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*(g) 22 -- | Amendment, dated November 8, 2015, to Service Agreement with Entergy Services (includes Amended and Restated Service Agreement for Administrative and General Support Services and Service Agreement for Generation Planning and Operational Support Services). |
(12) Statement Re Computation of Ratios
|
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| *(a) | Entergy Arkansas’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
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| *(b) | Entergy Louisiana’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Distributions, as defined. |
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| *(c) | Entergy Mississippi’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
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| *(d) | Entergy New Orleans’s Computation of Ratios of Earnings to Fixed Charges and of Earnings to Fixed Charges and Preferred Dividends, as defined. |
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| *(e) | Entergy Texas’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
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| *(f) | System Energy’s Computation of Ratios of Earnings to Fixed Charges, as defined. |
*(21) Subsidiaries of the Registrants
(23) Consents of Experts and Counsel
|
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| *(a) | The consent of Deloitte & Touche LLP is contained herein at page 512.518. |
*(24) Powers of Attorney
(31) Rule 13a-14(a)/15d-14(a) Certifications
|
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| *(a) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
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| *(b) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Corporation. |
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| *(c) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
|
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| *(d) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Arkansas. |
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| *(e) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
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| *(f) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Louisiana. |
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| *(g) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
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| *(h) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Mississippi. |
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| *(i) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
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| *(j) | Rule 13a-14(a)/15d-14(a) Certification for Entergy New Orleans. |
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| *(k) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
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| *(l) | Rule 13a-14(a)/15d-14(a) Certification for Entergy Texas. |
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| *(m) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
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| *(n) | Rule 13a-14(a)/15d-14(a) Certification for System Energy. |
(32) Section 1350 Certifications
|
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| *(a) | Section 1350 Certification for Entergy Corporation. |
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| *(b) | Section 1350 Certification for Entergy Corporation. |
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| *(c) | Section 1350 Certification for Entergy Arkansas. |
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| *(d) | Section 1350 Certification for Entergy Arkansas. |
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| *(e) | Section 1350 Certification for Entergy Louisiana. |
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| *(f) | Section 1350 Certification for Entergy Louisiana. |
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| *(g) | Section 1350 Certification for Entergy Mississippi. |
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| *(h) | Section 1350 Certification for Entergy Mississippi. |
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| *(i) | Section 1350 Certification for Entergy New Orleans. |
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| *(j) | Section 1350 Certification for Entergy New Orleans. |
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| *(k) | Section 1350 Certification for Entergy Texas. |
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| *(l) | Section 1350 Certification for Entergy Texas. |
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| *(m) | Section 1350 Certification for System Energy. |
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| *(n) | Section 1350 Certification for System Energy. |
(101) XBRL Documents
Entergy Corporation
|
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| *INS - | XBRL Instance Document. |
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| *SCH - | XBRL Taxonomy Extension Schema Document. |
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| *CAL - | XBRL Taxonomy Extension Calculation Linkbase Document. |
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| *DEF - | XBRL Taxonomy Extension Definition Linkbase Document. |
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| *LAB - | XBRL Taxonomy Extension Label Linkbase Document. |
| | |
| *PRE - | XBRL Taxonomy Extension Presentation Linkbase Document. |
_________________
|
| | |
| | * | Filed herewith. |
| | + | Management contracts or compensatory plans or arrangements. |